Attached files
file | filename |
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EXCEL - IDEA: XBRL DOCUMENT - CHESAPEAKE UTILITIES CORP | Financial_Report.xls |
EX-32.2 - EXHIBIT 32.2 - CHESAPEAKE UTILITIES CORP | c23743exv32w2.htm |
EX-31.2 - EXHIBIT 31.2 - CHESAPEAKE UTILITIES CORP | c23743exv31w2.htm |
EX-31.1 - EXHIBIT 31.1 - CHESAPEAKE UTILITIES CORP | c23743exv31w1.htm |
EX-32.1 - EXHIBIT 32.1 - CHESAPEAKE UTILITIES CORP | c23743exv32w1.htm |
Table of Contents
Securities and Exchange Commission
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Delaware | 51-0064146 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
(Address of principal executive offices, including Zip Code)
(Registrants telephone number, including area code)
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o | Smaller reporting company o |
Table of Contents
Subsidiaries
of Chesapeake Utilities Corporation |
||
BravePoint
|
BravePoint®, Inc. is a wholly-owned subsidiary of Chesapeake Services Company, which is a wholly-owned subsidiary of Chesapeake | |
Chesapeake
|
The Registrant, the Registrant and its subsidiaries, or the Registrants subsidiaries, as appropriate in the context of the disclosure | |
Company
|
The Registrant, the Registrant and its subsidiaries, or the Registrants subsidiaries, as appropriate in the context of the disclosure | |
Eastern Shore
|
Eastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake | |
FPU
|
Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake, effective October 28, 2009 | |
PESCO
|
Peninsula Energy Services Company, Inc., a wholly-owned subsidiary of Chesapeake | |
Peninsula Pipeline
|
Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake | |
Sharp
|
Sharp Energy, Inc., a wholly-owned subsidiary of Chesapeakes and Sharps subsidiary, Sharpgas, Inc. | |
Xeron
|
Xeron, Inc., a wholly-owned subsidiary of Chesapeake | |
Regulatory
Agencies |
||
Delaware PSC
|
Delaware Public Service Commission | |
EPA
|
United States Environmental Protection Agency | |
FERC
|
Federal Energy Regulatory Commission | |
FDEP
|
Florida Department of Environmental Protection | |
FDOT
|
Florida Department of Transportation | |
Florida PSC
|
Florida Public Service Commission | |
Maryland PSC
|
Maryland Public Service Commission | |
MDE
|
Maryland Department of the Environment | |
PSC
|
Public Service Commission | |
SEC
|
Securities and Exchange Commission | |
Accounting
Standards Related |
||
FASB
|
Financial Accounting Standards Board | |
GAAP
|
Generally Accepted Accounting Principles | |
Other |
||
AS/SVE
|
Air Sparging and Soil/Vapor Extraction | |
BS/SVE
|
Bio-Sparging and Soil/Vapor Extraction | |
CDD
|
Cooling Degree-Days | |
DSCP
|
Directors Stock Compensation Plan | |
Dts
|
Dekatherms | |
Dts/d
|
Dekatherms per day | |
ECCR
|
Energy Conservation Cost Recovery | |
FGT
|
Florida Gas Transmission Company | |
FRP
|
Fuel Retention Percentage | |
GSR
|
Gas Sales Service Rates | |
Gulf Power
|
Gulf Power Corporation | |
Gulfstream
|
Gulfstream Natural Gas System, LLC | |
HDD
|
Heating Degree-Days | |
MWH
|
Megawatt Hour | |
Mcf
|
Thousand Cubic Feet | |
MGP
|
Manufactured Gas Plant | |
NYSE
|
New York Stock Exchange | |
OCI
|
Other Comprehensive Income | |
OTC
|
Over-the-Counter | |
PIP
|
Performance Incentive Plan | |
RAP
|
Remedial Action Plan | |
Sanford Group
|
FPU and Other Responsible Parties involved with the Sanford Environmental Site | |
TETLP
|
Texas Eastern Transmission, LP | |
TOU
|
Time-of-Use |
Table of Contents
Item 1. | Financial Statements |
For the Three Months Ended September 30, | 2011 | 2010 | ||||||
(in thousands, except shares and per share data) | ||||||||
Operating Revenues |
||||||||
Regulated energy |
$ | 53,789 | $ | 53,412 | ||||
Unregulated energy |
23,721 | 20,134 | ||||||
Other |
3,100 | 2,920 | ||||||
Total operating revenues |
80,610 | 76,466 | ||||||
Operating Expenses |
||||||||
Regulated energy cost of sales |
25,811 | 27,257 | ||||||
Unregulated energy and other cost of sales |
20,306 | 17,238 | ||||||
Operations |
19,560 | 18,322 | ||||||
Maintenance |
2,029 | 1,899 | ||||||
Depreciation and amortization |
4,978 | 4,688 | ||||||
Other taxes |
2,332 | 2,479 | ||||||
Total operating expenses |
75,016 | 71,883 | ||||||
Operating Income |
5,594 | 4,583 | ||||||
Other income, net of expenses |
649 | 102 | ||||||
Interest charges |
2,389 | 2,256 | ||||||
Income Before Income Taxes |
3,854 | 2,429 | ||||||
Income tax expense |
1,457 | 801 | ||||||
Net Income |
$ | 2,397 | $ | 1,628 | ||||
Weighted-Average Common Shares Outstanding: |
||||||||
Basic |
9,564,012 | 9,493,425 | ||||||
Diluted |
9,657,970 | 9,497,696 | ||||||
Earnings Per Share of Common Stock: |
||||||||
Basic |
$ | 0.25 | $ | 0.17 | ||||
Diluted |
$ | 0.25 | $ | 0.17 | ||||
Cash Dividends Declared Per Share of Common
Stock |
$ | 0.345 | $ | 0.330 |
- 1 -
Table of Contents
For the Nine Months Ended September 30, | 2011 | 2010 | ||||||
(in thousands, except shares and per share data) | ||||||||
Operating Revenues |
||||||||
Regulated energy |
$ | 193,118 | $ | 197,779 | ||||
Unregulated energy |
112,164 | 104,018 | ||||||
Other |
8,757 | 7,990 | ||||||
Total operating revenues |
314,039 | 309,787 | ||||||
Operating Expenses |
||||||||
Regulated energy cost of sales |
98,683 | 106,146 | ||||||
Unregulated energy and other cost of sales |
89,017 | 82,713 | ||||||
Operations |
59,796 | 55,847 | ||||||
Maintenance |
5,624 | 5,388 | ||||||
Depreciation and amortization |
14,936 | 14,075 | ||||||
Other taxes |
7,774 | 7,876 | ||||||
Total operating expenses |
275,830 | 272,045 | ||||||
Operating Income |
38,209 | 37,742 | ||||||
Other income, net of expenses |
699 | 206 | ||||||
Interest charges |
6,654 | 6,924 | ||||||
Income Before Income Taxes |
32,254 | 31,024 | ||||||
Income tax expense |
12,590 | 12,082 | ||||||
Net Income |
$ | 19,664 | $ | 18,942 | ||||
Weighted-Average Common Shares Outstanding: |
||||||||
Basic |
9,552,472 | 9,460,462 | ||||||
Diluted |
9,647,632 | 9,570,921 | ||||||
Earnings Per Share of Common Stock: |
||||||||
Basic |
$ | 2.06 | $ | 2.00 | ||||
Diluted |
$ | 2.04 | $ | 1.98 | ||||
Cash Dividends Declared Per Share of Common
Stock |
$ | 1.020 | $ | 0.975 | ||||
- 2 -
Table of Contents
For the Nine Months Ended September 30, | 2011 | 2010 | ||||||
(in thousands) | ||||||||
Operating Activities |
||||||||
Net Income |
$ | 19,664 | $ | 18,942 | ||||
Adjustments to reconcile net income to net cash provided
by operating activities: |
||||||||
Depreciation and amortization |
14,936 | 14,075 | ||||||
Depreciation and accretion included in other costs |
3,755 | 3,248 | ||||||
Deferred income taxes, net |
14,183 | 9,847 | ||||||
(Gain) loss on sale of assets |
(449 | ) | 37 | |||||
Unrealized gain on commodity contracts |
(33 | ) | (443 | ) | ||||
Unrealized gain on investments |
(51 | ) | (13 | ) | ||||
Employee benefits |
(607 | ) | (594 | ) | ||||
Share-based compensation |
1,078 | 899 | ||||||
Other, net |
(43 | ) | (155 | ) | ||||
Changes in assets and liabilities: |
||||||||
Sale (purchase) of investments |
699 | (234 | ) | |||||
Accounts receivable and accrued revenue |
28,975 | 23,337 | ||||||
Propane inventory, storage gas and other inventory |
159 | (411 | ) | |||||
Regulatory assets |
962 | 967 | ||||||
Prepaid expenses and other current assets |
(744 | ) | 621 | |||||
Accounts payable and other accrued liabilities |
(25,783 | ) | (13,977 | ) | ||||
Income taxes receivable |
(3,064 | ) | (6,392 | ) | ||||
Accrued interest |
1,562 | 1,381 | ||||||
Customer deposits and refunds |
727 | 1,891 | ||||||
Accrued compensation |
(1,220 | ) | 735 | |||||
Regulatory liabilities |
(1,534 | ) | 453 | |||||
Other liabilities |
(398 | ) | 580 | |||||
Net cash provided by operating activities |
52,774 | 54,794 | ||||||
Investing Activities |
||||||||
Property, plant and equipment expenditures |
(33,377 | ) | (26,201 | ) | ||||
Proceeds from sales of assets |
905 | 90 | ||||||
Purchase of investments |
(300 | ) | (2,308 | ) | ||||
Environmental expenditures |
(525 | ) | (522 | ) | ||||
Net cash used in investing activities |
(33,297 | ) | (28,941 | ) | ||||
Financing Activities |
||||||||
Common stock dividends |
(8,673 | ) | (8,187 | ) | ||||
(Purchase) issuance of stock for Dividend Reinvestment Plan |
(920 | ) | 405 | |||||
Change in cash overdrafts due to outstanding checks |
1,079 | 7,020 | ||||||
Net repayment under line of credit agreements |
(9,346 | ) | (23,069 | ) | ||||
Other short-term borrowing |
(29,100 | ) | 29,100 | |||||
Proceeds from issuance of long-term debt |
29,000 | | ||||||
Repayment of long-term debt |
(1,390 | ) | (31,207 | ) | ||||
Net cash used in financing activities |
(19,350 | ) | (25,938 | ) | ||||
Net Increase (decrease) in Cash and Cash Equivalents |
127 | (85 | ) | |||||
Cash and Cash Equivalents Beginning of Period |
1,643 | 2,828 | ||||||
Cash and Cash Equivalents End of Period |
$ | 1,770 | $ | 2,743 | ||||
- 3 -
Table of Contents
September 30, | December 31, | |||||||
Assets | 2011 | 2010 | ||||||
(in thousands, except shares and per share data) | ||||||||
Property, Plant and Equipment |
||||||||
Regulated energy |
$ | 519,713 | $ | 500,689 | ||||
Unregulated energy |
62,828 | 61,313 | ||||||
Other |
19,359 | 16,989 | ||||||
Total property, plant and equipment |
601,900 | 578,991 | ||||||
Less: Accumulated depreciation and amortization |
(133,751 | ) | (121,628 | ) | ||||
Plus: Construction work in progress |
10,610 | 5,394 | ||||||
Net property, plant and equipment |
478,759 | 462,757 | ||||||
Investments, at fair value |
3,688 | 4,036 | ||||||
Current Assets |
||||||||
Cash and cash equivalents |
1,770 | 1,643 | ||||||
Accounts receivable (less allowance for
uncollectible
accounts of $906 and $1,194, respectively) |
65,692 | 88,074 | ||||||
Accrued revenue |
8,434 | 14,978 | ||||||
Propane inventory, at average cost |
8,351 | 8,876 | ||||||
Other inventory, at average cost |
2,946 | 3,084 | ||||||
Regulatory assets |
499 | 51 | ||||||
Storage gas prepayments |
5,558 | 5,084 | ||||||
Income taxes receivable |
9,812 | 6,748 | ||||||
Deferred income taxes |
1,264 | 2,191 | ||||||
Prepaid expenses |
5,549 | 4,613 | ||||||
Mark-to-market energy assets |
1,229 | 1,642 | ||||||
Other current assets |
212 | 245 | ||||||
Total current assets |
111,316 | 137,229 | ||||||
Deferred Charges and Other Assets |
||||||||
Goodwill |
35,613 | 35,613 | ||||||
Other intangible assets, net |
3,210 | 3,459 | ||||||
Long-term receivables |
51 | 155 | ||||||
Regulatory assets |
21,644 | 23,884 | ||||||
Other deferred charges |
3,235 | 3,860 | ||||||
Total deferred charges and other assets |
63,753 | 66,971 | ||||||
Total Assets |
$ | 657,516 | $ | 670,993 | ||||
- 4 -
Table of Contents
September 30, | December 31, | |||||||
Capitalization and Liabilities | 2011 | 2010 | ||||||
(in thousands, except shares and per share data) | ||||||||
Capitalization |
||||||||
Stockholders equity |
||||||||
Common stock, par value $0.4867 per share
(authorized 25,000,000 shares) |
$ | 4,655 | $ | 4,635 | ||||
Additional paid-in capital |
149,091 | 148,159 | ||||||
Retained earnings |
86,619 | 76,805 | ||||||
Accumulated other comprehensive loss |
(2,817 | ) | (3,360 | ) | ||||
Deferred compensation obligation |
807 | 777 | ||||||
Treasury stock |
(807 | ) | (777 | ) | ||||
Total stockholders equity |
237,548 | 226,239 | ||||||
Long-term debt, net of current maturities |
117,069 | 89,642 | ||||||
Total capitalization |
354,617 | 315,881 | ||||||
Current Liabilities |
||||||||
Current portion of long-term debt |
9,196 | 9,216 | ||||||
Short-term borrowing |
26,591 | 63,958 | ||||||
Accounts payable |
38,539 | 65,541 | ||||||
Customer deposits and refunds |
27,769 | 26,317 | ||||||
Accrued interest |
3,351 | 1,789 | ||||||
Dividends payable |
3,300 | 3,143 | ||||||
Accrued compensation |
5,665 | 6,784 | ||||||
Regulatory liabilities |
7,628 | 9,009 | ||||||
Mark-to-market energy liabilities |
956 | 1,492 | ||||||
Other accrued liabilities |
11,785 | 10,393 | ||||||
Total current liabilities |
134,780 | 197,642 | ||||||
Deferred Credits and Other Liabilities |
||||||||
Deferred income taxes |
93,650 | 80,031 | ||||||
Deferred investment tax credits |
187 | 243 | ||||||
Regulatory liabilities |
3,581 | 3,734 | ||||||
Environmental liabilities |
9,615 | 10,587 | ||||||
Other pension and benefit costs |
16,596 | 18,199 | ||||||
Accrued asset removal cost Regulatory
liability |
36,280 | 35,092 | ||||||
Other liabilities |
8,210 | 9,584 | ||||||
Total deferred credits and other liabilities |
168,119 | 157,470 | ||||||
Other commitments and contingencies (Note 4
and 5) |
||||||||
Total Capitalization and Liabilities |
$ | 657,516 | $ | 670,993 | ||||
- 5 -
Table of Contents
Accumulated | ||||||||||||||||||||||||||||||||
Common Stock | Additional | Other | ||||||||||||||||||||||||||||||
Number of | Paid-In | Retained | Comprehensive | Deferred | Treasury | |||||||||||||||||||||||||||
(in thousands, except shares and per share data) | Shares(6) | Par Value | Capital | Earnings | Loss | Compensation | Stock | Total | ||||||||||||||||||||||||
Balances at December 31, 2009 |
9,394,314 | $ | 4,572 | $ | 144,502 | $ | 63,231 | $ | (2,524 | ) | $ | 739 | $ | (739 | ) | $ | 209,781 | |||||||||||||||
Net Income |
26,056 | 26,056 | ||||||||||||||||||||||||||||||
Other comprehensive income, net of tax: |
||||||||||||||||||||||||||||||||
Employee Benefit Plans, net of tax: |
||||||||||||||||||||||||||||||||
Amortization of prior service costs
(4) |
8 | 8 | ||||||||||||||||||||||||||||||
Net Loss(5) |
(844 | ) | (844 | ) | ||||||||||||||||||||||||||||
Total comprehensive income |
25,220 | |||||||||||||||||||||||||||||||
Dividend Reinvestment Plan |
53,806 | 26 | 1,699 | 1,725 | ||||||||||||||||||||||||||||
Retirement Savings Plan |
27,795 | 14 | 889 | 903 | ||||||||||||||||||||||||||||
Conversion of debentures |
11,865 | 6 | 196 | 202 | ||||||||||||||||||||||||||||
Share based compensation (1) (3) |
36,415 | 17 | 620 | 637 | ||||||||||||||||||||||||||||
Tax benefit
on share based compensation |
253 | 253 | ||||||||||||||||||||||||||||||
Deferred Compensation Plan |
38 | (38 | ) | | ||||||||||||||||||||||||||||
Purchase of treasury stock |
(1,144 | ) | (38 | ) | (38 | ) | ||||||||||||||||||||||||||
Sale and distribution of treasury stock |
1,144 | 38 | 38 | |||||||||||||||||||||||||||||
Dividends on share-based compensation |
(104 | ) | (104 | ) | ||||||||||||||||||||||||||||
Cash dividends (2) |
(12,378 | ) | (12,378 | ) | ||||||||||||||||||||||||||||
Balances at December 31, 2010 |
9,524,195 | 4,635 | 148,159 | 76,805 | (3,360 | ) | 777 | (777 | ) | 226,239 | ||||||||||||||||||||||
Net Income |
19,664 | 19,664 | ||||||||||||||||||||||||||||||
Other comprehensive income, net of tax: |
||||||||||||||||||||||||||||||||
Employee Benefit Plans, net of tax: |
||||||||||||||||||||||||||||||||
Amortization of prior service costs
(4) |
6 | 6 | ||||||||||||||||||||||||||||||
Net Gain (5) |
537 | 537 | ||||||||||||||||||||||||||||||
Total comprehensive income |
20,207 | |||||||||||||||||||||||||||||||
Dividend Reinvestment Plan |
| | (16 | ) | (16 | ) | ||||||||||||||||||||||||||
Retirement Savings Plan |
2,002 | 1 | 79 | 80 | ||||||||||||||||||||||||||||
Conversion of debentures |
8,039 | 4 | 132 | 136 | ||||||||||||||||||||||||||||
Share based compensation (1) (3) |
30,430 | 15 | 737 | 752 | ||||||||||||||||||||||||||||
Deferred Compensation Plan |
30 | (30 | ) | | ||||||||||||||||||||||||||||
Purchase of treasury stock |
(731 | ) | (30 | ) | (30 | ) | ||||||||||||||||||||||||||
Sale and distribution of treasury stock |
731 | 30 | 30 | |||||||||||||||||||||||||||||
Dividends on share-based compensation |
(100 | ) | (100 | ) | ||||||||||||||||||||||||||||
Cash dividends (2) |
(9,750 | ) | (9,750 | ) | ||||||||||||||||||||||||||||
Balances at September 30, 2011 |
9,564,666 | $ | 4,655 | $ | 149,091 | $ | 86,619 | $ | (2,817 | ) | $ | 807 | $ | (807 | ) | $ | 237,548 | |||||||||||||||
(1) | Includes amounts for shares issued for Directors compensation. |
|
(2) | Cash dividends declared per share for the periods ended September 30, 2011 and
December 31, 2010 were $1.02 and $1.305, respectively. |
|
(3) | The shares issued under the Performance Incentive Plan (PIP) are net of shares
withheld for employee taxes. For the periods ended September 30, 2011 and December 31, 2010 the
Company withheld 12,324 and 17,695, respectively, shares for taxes. |
|
(4) | Tax expense recognized on the prior service cost component of employees benefit
plans for the periods ended September 30, 2011 and December 31, 2010 were approximately $4 and $5,
respectively.
|
|
(5) | Tax expense (benefit) recognized on the net gain (loss) component of
employees benefit plans for the periods ended September 30, 2011 and December 31, 2010, were $359
and ($541), respectively. |
|
(6) | Includes 30,335 and 29,596 shares at September 30, 2011
and December 31, 2010, respectively, held in a Rabbi Trust established by the Company relating to
the Deferred Compensation Plan. |
- 6 -
Table of Contents
1. | Summary of Accounting Policies |
Basis of Presentation |
References in this document to the Company, Chesapeake, we, us and our are intended to
mean the Registrant and its subsidiaries, or the Registrants subsidiaries, as appropriate in
the context of the disclosure. |
The accompanying unaudited condensed consolidated financial statements have been prepared in
compliance with the rules and regulations of the Securities and Exchange Commission (SEC) and
United States of America Generally Accepted Accounting Principles (GAAP). In accordance with
these rules and regulations, certain information and disclosures normally required for audited
financial statements have been condensed or omitted. These financial statements should be read
in conjunction with the consolidated financial statements and notes thereto, included in our
latest Annual Report on Form 10-K filed with the SEC on March 8, 2011. In the opinion of
management, these financial statements reflect normal recurring adjustments that are necessary
for a fair presentation of our results of operations, financial position and cash flows for the
interim periods presented. |
Due to the seasonality of our business, results for interim periods are not necessarily
indicative of results for the entire fiscal year. Revenue and earnings are typically greater
during the first and fourth quarters, when consumption of energy is highest due to colder
temperatures. |
We have assessed and reported on subsequent events through the date of issuance of these
condensed consolidated financial statements. |
Sale of Assets |
In July 2011, we sold
an Internet Protocol address asset to an unaffiliated entity for approximately
$553,000. This particular Internet Protocol address was not used by
us and did not have any net
carrying value at the time of the sale. We recognized a non-operating gain of $553,000 from
this sale, which is included in other income in the accompanying condensed consolidated
statements of income. |
In September 2011, we entered into an agreement with an unaffiliated entity to sell our office
building located in West Palm Beach, Florida for $2.2 million. We also entered into a separate
agreement to lease an office space at a different location in West Palm Beach, which is expected
to commence in February 2012. The sale of our West Palm Beach office building is expected to be
finalized in February 2012, at which point we expect to move some of the approximately 70
employees currently located in this building into the newly leased office space and the
remaining employees into another nearby operational center in West Palm Beach, which we own. We
are treating the West Palm Beach office building as an asset held for sale. The office building
is included in other property, plant and equipment in the accompanying condensed consolidated
balance sheets and had a net carrying value of approximately $2.0 million at September 30, 2011.
Since the expected sales price, less costs to consummate the sale, exceed the net carrying
value of the building, there was no impairment related to the West Palm Beach office building
when we committed to the sale. As most of the West Palm Beach building is considered a property
within the regulated businesses, most of the gain resulted from the sale will be charged to
accumulated depreciation. |
Reclassifications |
We reclassified certain amounts in the condensed consolidated statements of income for the three
and nine months ended September 30, 2010, and the condensed consolidated statement of cash flows
for the nine months ended September 30, 2010, to conform to the current years presentation.
These reclassifications are considered immaterial to the overall presentation of our condensed
consolidated financial statements. |
- 7 -
Table of Contents
Recent Accounting Amendments Yet to be Adopted by the Company |
In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards
Update (ASU) No. 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common
Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. Amendments in the ASU
do not extend the use of fair value accounting but provide guidance on how it should be applied
where its use is already required or permitted by other standards within International Financial
Accounting Standards (IFRS) or U.S. GAAP. ASU 2011-04 supersedes most of the guidance in Topic
820, although many of the changes are clarifications of existing guidance or wording changes to
align with IFRS. Certain amendments in ASU 2011-04 change a particular principle or requirement
for measuring fair value or disclosing information about fair value measurements. The amendments
in ASU 2011-04 are effective for public entities for interim and annual periods beginning after
December 15, 2011, and should be applied prospectively. Early adoption is not permitted for
public entities. We expect the adoption of ASU 2011-04 to have no material impact on our
financial position and results of operations. |
In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income. ASU 2011-05
amends the guidance in Topic 220 Comprehensive Income, by eliminating the option to present
components of other comprehensive income (OCI) in the statement of stockholders equity. Instead, the
new guidance now requires entities to present all non-owner changes in stockholders equity
either as a single continuous statement of comprehensive income or as two separate but
consecutive statements. The components of OCI have not changed
nor has the guidance on when OCI items are reclassified to net income; however, the amendments
require entities to present all reclassification adjustments from OCI to net income on the face
of the statement of comprehensive income. Similarly, ASU 2011-05 does not change the guidance to
disclose OCI components gross or net of the effect of income taxes, provided that the tax
effects are presented on the face of the statement in which OCI is presented, or disclosed in
the notes to the financial statements. For public entities, the amendments in ASU 2011-05 are
effective for fiscal years, and for interim periods within those fiscal years, beginning after
December 15, 2011. The amendments should be applied retrospectively, and early adoption is
permitted. We plan to comply with the new OCI presentation at the end of 2011. |
In September 2011, the FASB issued ASU 2011-08, Intangibles Goodwill and Other (Topic 350)
Testing Goodwill for Impairment. ASU 2011-08 allows an entity to assess qualitatively whether
it is necessary to perform step one of the two-step annual goodwill impairment test. Step one
would be required if it is more-likely-than-not that a reporting units fair value is less than
its carrying amount. This is different than previous guidance, which required entities to
perform step one of the test, at least annually, by comparing the fair value of a reporting unit
to its carrying amount. An entity may elect to bypass the qualitative assessment and proceed
directly to step one, for any reporting unit, in any period. ASU 2011-08 does not change the
guidance on when to test goodwill for impairment. The amendments in ASU 2011-08 are effective
for annual and interim goodwill impairment tests performed for fiscal years beginning after
December 15, 2011. We expect the adoption of ASU 2011-08 to have no material impact on our
financial position and results of operations.
|
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2. | Calculation of Earnings Per Share |
Three Months | Nine Months | |||||||||||||||
For the Periods Ended September 30, | 2011 | 2010 | 2011 | 2010 | ||||||||||||
(in thousands, except shares and per share data) | ||||||||||||||||
Calculation of Basic Earnings Per Share: |
||||||||||||||||
Net Income |
$ | 2,397 | $ | 1,628 | $ | 19,664 | $ | 18,942 | ||||||||
Weighted average shares outstanding |
9,564,012 | 9,493,425 | 9,552,472 | 9,460,462 | ||||||||||||
Basic Earnings Per Share |
$ | 0.25 | $ | 0.17 | $ | 2.06 | $ | 2.00 | ||||||||
Calculation of Diluted Earnings Per Share: |
||||||||||||||||
Reconciliation of Numerator: |
||||||||||||||||
Net Income |
$ | 2,397 | $ | 1,628 | $ | 19,664 | $ | 18,942 | ||||||||
Effect of 8.25% Convertible debentures (1) |
15 | | 46 | 56 | ||||||||||||
Adjusted numerator Diluted |
$ | 2,412 | $ | 1,628 | $ | 19,710 | $ | 18,998 | ||||||||
Reconciliation of Denominator: |
||||||||||||||||
Weighted shares outstanding Basic |
9,564,012 | 9,493,425 | 9,552,472 | 9,460,462 | ||||||||||||
Effect of dilutive securities (1): |
||||||||||||||||
Share-based Compensation |
23,925 | 4,271 | 22,623 | 23,708 | ||||||||||||
8.25% Convertible debentures |
70,033 | | 72,537 | 86,751 | ||||||||||||
Adjusted denominator Diluted |
9,657,970 | 9,497,696 | 9,647,632 | 9,570,921 | ||||||||||||
Diluted Earnings Per Share |
$ | 0.25 | $ | 0.17 | $ | 2.04 | $ | 1.98 | ||||||||
(1) | Amounts associated with securities resulting in an anti-dilutive effect on earnings per
share are not included in this calculation. |
3. | Rates and Other Regulatory Activities |
Our natural gas and electric distribution operations in Delaware, Maryland and Florida are
subject to regulation by their respective Public Service Commission (PSC); Eastern Shore
Natural Gas Company (Eastern Shore), our natural gas transmission operation, is subject to
regulation by the Federal Energy Regulatory Commission (FERC); and Peninsula Pipeline Company,
Inc. (Peninsula Pipeline) is subject to regulation by the Florida PSC. Chesapeakes Florida
natural gas distribution division and the natural gas and electric distribution operations of
Florida Public Utilities Company (FPU) continue to be subject to regulation by the Florida PSC
as separate entities. |
Delaware |
Capacity Release: On September 2, 2008, our Delaware division filed with the Delaware PSC its
annual Gas Sales Service Rates (GSR) Application, seeking approval to change its GSR,
effective November 1, 2008. On July 7, 2009, the Delaware PSC granted approval of a settlement
agreement presented by the parties in this docket, which included the Delaware PSC, our Delaware
division and the Division of the Public Advocate. As part of the settlement agreement, the
parties agreed to develop a record in a later proceeding on the price charged by the Delaware
division for the temporary release of transmission pipeline capacity to our natural gas
marketing subsidiary, Peninsula Energy Services Company, Inc. (PESCO). On January 8, 2010,
the Hearing Examiner in this proceeding issued a report of Findings and Recommendations in which
he recommended, among other things, that the Delaware PSC require the Delaware division to
refund to its firm service customers the difference between what the Delaware division would
have received had the capacity released to PESCO been priced at the maximum tariff rates under
asymmetrical pricing principles and the amount actually received by the Delaware division for
capacity released to PESCO. The Hearing Examiner also recommended that the Delaware PSC require
us to adhere to asymmetrical pricing principles in all future capacity releases by the Delaware
division to PESCO, if any. If the Hearing Examiners refund recommendation for past capacity
releases were ultimately approved without modification by the Delaware PSC, the Delaware
division would have to credit to its firm service customers amounts equal to the maximum tariff
rates that the Delaware division pays for long-term capacity, which we estimated to be
approximately $700,000, even though the temporary releases were made at lower rates based on
competitive bidding procedures required by the FERCs capacity release rules. On February 18,
2010, we filed exceptions to the Hearing Examiners recommendations. |
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At the hearing on March 30, 2010, the Delaware PSC agreed with us that the Delaware division had
been releasing capacity based on a previous settlement approved by the Delaware PSC and,
therefore, did not require the Delaware division to issue any refunds for past capacity
releases. The Delaware PSC, however, required the Delaware division to adhere to asymmetrical
pricing principles for future capacity releases to PESCO until a more appropriate pricing
methodology is developed and approved. The Delaware PSC issued an order on May 18, 2010,
elaborating its decisions at the March hearing and directing the parties to reconvene in a
separate docket to determine if a pricing methodology other than asymmetrical pricing principles
should apply to future capacity releases by the Delaware division to PESCO. |
On June 17, 2010, the Division of the Public Advocate filed an appeal with the Delaware Superior
Court, asking it to overturn the Delaware PSCs decision with regard to refunds for past
capacity releases. On June 28, 2010, the Delaware division filed a Notice of Cross Appeal with
the Delaware Superior Court, asking it to overturn the Delaware PSCs decision with regard to
requiring the Delaware division to adhere to asymmetrical pricing principles for future capacity
releases to PESCO. On June 13, 2011, the Delaware Superior Court issued its decision affirming
all aspects of the Delaware PSCs Order on May 18, 2010, which included its decision not to
require the Delaware division to issue any refunds for past releases. |
On June 29, 2011, the Delaware Attorney General filed an appeal with the Delaware Supreme Court,
asking it to review the Delaware Superior Courts decision affirming the Delaware PSC decision
with regard to refunds for past capacity releases. On July 12, 2011, the Delaware division filed
a Notice of Cross Appeal with the Delaware Supreme Court, asking it to overturn the Superior
Courts decision with regard to the Delaware PSCs decision on future capacity releases to
PESCO. On August 3, 2011, the Delaware Attorney General filed a Notice of Dismissal with the
Supreme Court in which the Delaware Attorney General withdrew its appeal. Consequently, on
August 4, 2011, the Delaware division filed a Notice of Dismissal with the Supreme Court to
withdrawal its cross appeal. This officially closes the case and eliminates any potential
liability related to potential refunds for past capacity releases. Due to the ongoing legal
proceedings, the parties have not yet opened a separate docket to determine an alternative
pricing methodology for future capacity releases. |
Our Delaware division also had developments in the following matters with the Delaware PSC: |
On September 1, 2010, the Delaware division filed with the Delaware PSC its annual GSR
Application, seeking approval to change its GSR, effective November 1, 2010. On September 21,
2010, the Delaware PSC authorized the Delaware division to implement the GSR charges on
November 1, 2010, on a temporary basis, subject to refund, pending the completion of full
evidentiary hearings and a final decision. The Delaware PSC granted approval of the GSR
charges at its regularly scheduled meeting on June 7, 2011. |
On March 10, 2011, the Delaware division filed with the Delaware PSC an application requesting
approval to guarantee certain debt of FPU. Specifically, the Delaware division sought
approval to execute a Seventeenth Supplemental Indenture, in which Chesapeake guarantees the
payment of certain debt of FPU and FPU is permitted to deliver Chesapeakes consolidated
financial statements in lieu of FPUs stand-alone financial statements to satisfy certain
covenants within the indentures of FPUs debt. The Delaware PSC granted approval of the
guarantee of certain debt of FPU at its regularly scheduled meeting on April 4, 2011. |
On September 1, 2011, the Delaware division filed with the Delaware PSC its annual GSR
Application, seeking approval to change its GSR, effective November 1, 2011. On September 20,
2011, the Delaware PSC authorized the Delaware division to implement the GSR charges, as
filed, on November 1, 2011, on a temporary basis, subject to refund, pending the completion of
full evidentiary hearings and a final decision. We anticipate that the Delaware PSC will
render a final decision on the GSR charges in the second or third quarter of 2012. |
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On September 19, 2011, the Delaware division filed with the Delaware PSC two applications
seeking approval to begin charging customers for the franchise fees imposed upon the Delaware
division by the City of Lewes, Delaware and the Town of Dagsboro, Delaware. These
applications are very similar to requests the Delaware PSC has already approved for six other
local governments. On October 3, 2011, the Delaware PSC issued orders on both matters,
effectively opening the proceedings and setting evidentiary hearings for November 8, 2011. We
anticipate that the Delaware PSC will render a decision in the fourth quarter of 2011. |
Maryland |
On December 14, 2010, the Maryland PSC held an evidentiary hearing to determine the
reasonableness of the four quarterly gas cost recovery filings submitted by the Maryland
division during the 12 months ended September 30, 2010. No issues were raised at the hearing,
and on December 20, 2010, the Hearing Examiner in
this proceeding issued a proposed Order approving the divisions four quarterly filings. This
proposed Order became a final Order of the Maryland PSC on January 20, 2011. |
On March 2, 2011, the Maryland division filed with the Maryland PSC an application for the
approval of a franchise executed between the Maryland division and the Board of County
Commissioners of Cecil County, Maryland. In this franchise agreement, the County granted the
Maryland division a 50-year, non-exclusive franchise to construct and operate natural gas
distribution facilities within the present and future jurisdictional boundaries of Cecil County.
On April 11, 2011, the Maryland PSC issued an Order approving the franchise between the
Maryland division and Cecil County, subject to no adverse comments being received within 30 days
after the issuance of the Order. On May 10, 2011, comments opposing the application were filed
by Pivotal Utility Holdings, Inc. d/b/a Elkton Gas (Pivotal). Pivotal also provides natural
gas service to customers in a portion of Cecil County. On June 8, 2011, the Maryland PSC granted
the Maryland division the authority to exercise its franchise in a majority of the area
requested in the Maryland divisions application. The approval for a small portion of the area
within the requested franchise area, which is closest to the area served by Pivotal, has been
withheld until an evidentiary hearing is convened. On August 16, 2011, the Maryland division
submitted testimony in support of its proposed boundary with Pivotal. On September 29, 2011,
the parties in the proceeding (Maryland division, Pivotal, Maryland PSC Staff, and the Office of
Peoples Counsel) submitted a proposed settlement agreement for the Maryland PSCs consideration
that outlines an agreed upon boundary between the Maryland division and Pivotal in the small
portion of Cecil County that was subject to further review. On
October 12, 2011, the assigned Public Utility Law Judge in this
matter issued a Proposed Order, approving the proposed settlement
agreement as submitted by the parties in the proceeding. The Proposed
Order will become a final order of the Maryland PSC on November 15,
2011, unless an appeal is noted with the Maryland PSC before that
date by any party to this proceeding, or the Maryland PSC modifies or
reverses the Proposed Order or initiates further proceedings into
this matter. |
On May 17, 2011, the Maryland division filed with the Maryland PSC an application for approval
of a franchise executed between the Maryland division and the Board of County Commissioners for
Worcester County, Maryland. In this franchise agreement, the County granted the Maryland
division a 25-year, non-exclusive, franchise to construct and operate natural gas distribution
facilities within the present and future jurisdictional boundaries of Worcester County. On June
14, 2011, the Maryland PSC issued an Order approving the franchise between the Maryland division
and Worcester County, subject to no adverse comments being received within 20 days after the
issuance of the Order. No adverse comments were filed within the comment period and the order
became effective on July 5, 2011. |
On August 12, 2011, the Maryland division submitted a request to the Maryland PSC for approval
of a negotiated delivery service rate for a large customer on its system. At its regularly
scheduled meeting on September 21, 2011, the Maryland PSC granted approval of the negotiated
delivery service rate effective for bills rendered after that date. |
Florida |
Come-Back Filing: As part of our 2010 rate case settlement in Florida, the Florida PSC
required us to submit a Come-Back filing, detailing all known benefits, synergies, cost
savings and cost increases resulting from the merger with FPU. We submitted this filing on
April 29, 2011. We are requesting the recovery, through rates, of approximately $34.2 million
in acquisition adjustment (the price paid in excess of the book value) and $2.2 million in
merger-related costs. In the past, the Florida PSC has allowed recovery of an acquisition
adjustment under certain circumstances to provide an incentive for larger utilities to purchase
smaller utilities. The Florida PSC requires a company seeking recovery of the acquisition
adjustment and merger-related costs to demonstrate that customers will benefit from the
acquisition. They use the following five factor test to determine if the customers are
benefiting from the transaction: (a) increased quality of service; (b) lower operating costs;
(c) increased ability to attract capital for improvements; (d) lower overall cost of capital;
and (e) more professional and experienced managerial, financial, technical and operational
resources. With respect to lower costs, the Florida PSC effectively requires that the synergies
be sufficient to offset the rate impact of the recovery of the acquisition adjustment and
merger-related costs. The Florida PSC is expected to address our request for recovery of the
acquisition adjustment and merger-related costs at the November 2011 agenda conference. |
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If the Florida PSC approves recovery of the acquisition adjustment and merger-related costs, we
would be able to classify these amounts as regulatory assets and include them in our investment,
or rate base, when determining our Florida natural gas rates. Additionally, we would calculate
our rate of return based upon this higher level of investment, which would effectively enable us
to earn a return on this investment. We would also be able to amortize the acquisition
adjustment and merger-related costs over 30 and five years, respectively. Amortization
expense would be included in the calculation of our rates. |
If recovery of the acquisition adjustment and merger-related costs is approved, our earnings may
be reduced by as much as $1.6 million annually for the amortization expense (approximately $1.3
million is non-tax-deductible) until 2014 and $1.1 million annually (non-tax deductible)
thereafter until 2039. This amortization expense would be a non-cash charge, and the net
effect of the recovery would be positive cash flow. Over the long-term, however, the inclusion
of the acquisition adjustment and merger-related costs in our rate base and the recovery of
these regulatory assets through amortization expense will increase our earnings and cash flows
above what we would have otherwise been able to achieve. |
If the Florida PSC does not allow recovery of the acquisition adjustment and merger-related
costs, there is some likelihood that we would have to reduce rates in the State of Florida,
which would adversely affect our future earnings. |
We continue to maintain a $750,000 accrual, which was recorded in 2010 based on managements
assessment of FPUs earnings and regulatory risk to its earnings associated with possible
Florida PSC action related to our requested recovery and the matters set forth in this filing. |
Marianna Franchise: On July 7, 2009, the City Commission of Marianna, Florida (Marianna
Commission) adopted an ordinance granting a franchise to FPU effective February 1, 2010 for a
period not to exceed 10 years for the operation and distribution and/or sale of electric energy
(the Franchise Agreement). The Franchise Agreement provides that FPU will develop and
implement new time-of-use (TOU) and interruptible electric power rates, or other similar
rates, mutually agreeable to FPU and the City of Marianna. The Franchise Agreement further
provides for the TOU and interruptible rates to be effective no later than February 17, 2011,
and available to all customers within FPUs Northwest Division, which includes the City of
Marianna. If the rates were not in effect by February 17, 2011, the City of Marianna would have
the right to give notice to FPU within 180 days thereafter of its intent to exercise an option
in the Franchise Agreement to purchase FPUs property (consisting of the electric distribution
assets) within the City of Marianna. Any such purchase would be subject to approval by the
Marianna Commission, which would also need to approve the presentation of a referendum to voters
in the City of Marianna for the approval of the purchase and the operation by the City of
Marianna of an electric distribution facility. If the purchase is approved by the Marianna
Commission and by the referendum, the closing of the purchase must occur within 12 months after
the referendum is approved. If the City of Marianna elects to purchase the Marianna property,
the Franchise Agreement requires the City of Marianna to pay FPU the fair market value for such
property as determined by three qualified appraisers. Future financial results would be
negatively affected by the loss of earnings generated by FPU from its approximately 3,000
customers in the City under the Franchise Agreement. |
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In accordance with the terms of the Franchise Agreement, FPU developed TOU and interruptible
rates and on December 14, 2010, FPU filed a petition with the Florida PSC for authority to
implement such proposed TOU and interruptible rates on or before February 17, 2011. On February
11, 2011, the Florida PSC issued an Order approving FPUs petition for authority to implement
the proposed TOU and interruptible rates, which became effective on February 8, 2011. The City
of Marianna has objected to the proposed rates and has filed a petition protesting the entry of
the Florida PSCs Order. On March 17, 2011, FPU filed a Motion to Dismiss the petition by the
City of Marianna and requested oral argument. On June 14, 2011, the Florida PSC granted FPUs
request for oral argument and on July 5, 2011, issued an Order approving FPUs Motion to Dismiss
the protest by the City of Marianna, without prejudice. On July 25, 2011, the City of Marianna
filed an amended petition protesting the entry of the Florida PSCs Order. On August 12, 2011,
FPU filed a new Motion to Dismiss the
petition by the City of Marianna and requested oral argument. The Florida PSCs decision with
respect to the amended petition by the City of Marianna is expected in December 2011. |
On January 26, 2011, FPU filed a petition with the Florida PSC for approval of an amendment to
FPUs Generation Services Agreement entered into between FPU and Gulf Power Corporation (Gulf
Power). The amendment provides for a reduction in the capacity demand quantity, which generates
the savings necessary to support the TOU and interruptible rates approved by the Florida PSC.
The amendment also extends the current agreement by two years, with a new expiration date of
December 31, 2019. Pursuant to its Order dated June 21, 2011, the Florida PSC approved the
amendment. On July 12, 2011, the City of Marianna filed a protest of this decision and
requested a hearing on the amendment. On July 28, 2011, FPU filed a Motion to Dismiss the
petition by the City of Marianna and requested oral argument. The Florida PSCs decision with
respect to the protest filed by the City of Marianna is expected in December 2011. |
On April 7, 2011, FPU filed a petition for approval of a mid-course reduction to its Northwest
Division fuel rates based on two factors: (1) the previously discussed amendment to the
Generation Services Agreement with Gulf Power and (2) a weather-related increase in sales
resulting in an accelerated collection of the prior years under-recovered costs. Pursuant to
its Order dated July 5, 2011, the Florida PSC approved the petition, which is projected to
reduce customers fuel rates for the remaining months of 2011 by approximately 10 percent. |
As disclosed in Note 5, Other Commitments and Contingencies, to the unaudited condensed
consolidated financial statements, the City of Marianna, on March 2, 2011, filed a complaint
against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County,
Florida, alleging breaches of the Franchise Agreement by FPU and seeking a declaratory judgment
that the City of Marianna has the right to exercise its option to purchase FPUs property in the
City of Marianna in accordance with the terms of the Franchise Agreement. On March 28, 2011,
FPU filed its answer to the declaratory action by the City of Marianna, in which it denied the
material allegation by the City of Marianna and asserted several affirmative defenses. The
litigation remains pending and discovery is still underway. |
Eastern Shore |
The following are regulatory activities involving FERC Orders applicable to Eastern Shore and
the expansions of Eastern Shores transmission system: |
Energylink Expansion Project: In 2006, Eastern Shore proposed to develop, construct and operate
approximately 75 miles of new pipeline facilities from the existing Cove Point Liquefied Natural
Gas terminal in Calvert County, Maryland, crossing under the Chesapeake Bay into Dorchester and
Caroline Counties, Maryland, to points on the Delmarva Peninsula, where such facilities would
interconnect with Eastern Shores existing facilities in Sussex County, Delaware. In April 2009,
Eastern Shore terminated this project based on increased construction costs over its original
projection. As approved by the FERC, Eastern Shore initiated billing to recover approximately
$3.2 million of costs incurred in connection with this project and the related cost of capital
over a period of 20 years in accordance with the terms of the precedent agreements executed with
the two participating customers. One of the two participating customers is Chesapeake, through
its Delaware and Maryland divisions. During 2010, Eastern Shore and the participating customers
negotiated to reduce the recovery period of this cost from 20 years to five years. On January
27, 2011, Eastern Shore filed with the FERC the request to amend the cost recovery period, which
was approved by the FERC on February 14, 2011. Eastern Shore revised its billing to reflect the
five-year surcharge effective March 1, 2011. |
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Rate Case Filing: On December 30, 2010, Eastern Shore filed with the FERC a base rate
proceeding in accordance with the terms of the settlement in its prior base rate proceeding.
The rate filing reflects increases in operating and maintenance expenses, depreciation expense,
and a return on existing and new gas plant facilities expected to be placed into service before
June 30, 2011. The FERC issued a notice of the filing on January 3, 2011. Protests were
received from several interested parties, and other parties intervened in the proceeding. On
January 31, 2011, the FERC issued its Order accepting the filing and suspending its
effectiveness for the full five-month period permitted under the Natural Gas Act. The discovery
process commenced on February 22, 2011, and FERC Staff performed an on-site audit on March
16-17, 2011. Settlement conferences involving Eastern Shore, FERC Staff and other interested
parties have resulted in a settlement in principle, which provides a cost of service of
approximately $29.1 million and a pre-tax return of 13.9 percent. This represents an annual
rate increase of approximately $805,000, effective July 29, 2011. The settlement also includes
a rate reduction, effective November 1, 2011, associated with
the 15,000 Dekatherms per day (Dts/d)
phase-in of new transportation services on Eastern Shores eight-mile extension to
interconnect with the Texas Eastern Transmission LP (TETLP) pipeline system. This
rate reduction fully offsets the increased revenue that would have been generated from the
15,000 Dts/d increase in firm service. The settlement also provides a five-year moratorium on the parties
rights to challenge Eastern Shores rates and on Eastern Shores right to file a base rate
increase. The settlement allows Eastern Shore to file for rate adjustments during those five
years in the event certain costs related to government-mandated obligations are incurred and
Eastern Shores pre-tax earnings do not equal or exceed 13.9 percent. Eastern Shore expects to
finalize the settlement with the parties in November 2011 and submit it to the FERC for
approval. The FERCs approval is expected by late 2011 or early 2012. |
Starting in July 2011, Eastern Shore adjusted its billing to reflect the rates requested in the
base rate proceeding, subject to refund to customers upon the conclusion of this proceeding.
Eastern Shore recorded approximately $911,000 as a regulatory liability as of September 30, 2011,
to fully reserve any incremental revenues generated by the new rates until the settlement is
filed and approved by the FERC. |
Mainline Extension Project: On April 1, 2011, Eastern Shore filed a notice of its intent under
its blanket certificate to construct, own and operate new mainline facilities to deliver
additional firm service of 3,405 Dts/d of natural gas to an existing industrial customer. The
FERC published notice of this filing on April 7, 2011. The 60-day comment period subsequent to
the FERC notice expired on June 6, 2011, and the requested authorization became effective on
that date. |
On April 28, 2011, Eastern Shore filed a notice of intent under its blanket certificate to
construct, own and operate new mainline facilities to deliver additional firm service of 6,250
Dts/d of natural gas to Chesapeakes Delaware and Maryland divisions and Eastern Shore Gas, an
unaffiliated provider of piped propane service in Maryland. The FERC published notice of this
filing on May 12, 2011 and one of Eastern Shores customers filed a conditional protest with the
FERC, which it withdrew on July 29, 2011. Upon withdrawal of the protest, the requested
authorization became effective. |
Also on April 28, 2011, Eastern Shore filed a notice of intent under its blanket certificate to
construct, own and operate new mainline facilities to deliver additional firm service of 4,070
Dts/d of natural gas to Chesapeakes Maryland division to provide new natural gas service in
Cecil County, Maryland. The FERC published notice of this filing on May 12, 2011 and one of
Eastern Shores customers filed a conditional protest with the FERC, which it withdrew on July
29, 2011. Upon withdrawal of the protest, the requested authorization became effective. |
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Eastern Shore also had developments in the following FERC matters: |
On March 7, 2011, Eastern Shore filed certain tariff sheets to amend the creditworthiness
provisions contained in its FERC Gas Tariff. On April 6, 2011, the FERC issued an Order
accepting and suspending Eastern Shores filed tariff revisions for an effective date of April
1, 2011, subject to Eastern Shore submitting certain clarifications with regard to several
proposed revisions. |
On April 18, 2011, Eastern Shore submitted its annual Interruptible Revenue Sharing Report to
the FERC. Eastern Shore reported in this filing that its interruptible revenue did not exceed
its annual threshold amount, which would trigger sharing of excess interruptible revenues with
its firm service customers. Consequently,
Eastern Shore is not required to refund to its firm customers any portion of its interruptible
revenue received for the period April 2010 through March 2011. |
On June 24, 2011, Eastern Shore filed certain tariff sheets to amend the General Terms and
Conditions and the Firm Transportation Service Agreement contained in its FERC Gas Tariff to
allow for specification of minimum delivery pressures and maximum hourly quantity. The FERC
published the notice of this filing on June 27, 2011, and no protests or adverse comments
opposing this filing were submitted. On July 15, 2011, the FERC issued a Letter Order,
accepting the tariff revisions as proposed, effective July 24, 2011. |
On August 15, 2011, Eastern Shore filed certain tariff sheets to update certain Delivery Point
Area definitions contained in its FERC Gas Tariff. The FERC published the notice of this
filing on August 16, 2011, and no protests or adverse comments opposing this filing were
submitted. On September 13, 2011, the FERC issued a Letter Order, accepting the tariff
revisions as proposed, effective September 14, 2011. |
On September 7, 2011, Eastern Shore filed certain tariff sheets to reflect a decrease in the
Annual Charge Adjustment, which is a surcharge designed to recover applicable program costs
incurred by the FERC. The surcharge decreased from $0.0019 per Dt to $0.0018 per Dt. The
FERC published the notice of this filing on September 8, 2011, and no protests or adverse
comments opposing this filing were submitted. On September 27, 2011, the FERC issued a Letter
Order, accepting the tariff revisions as proposed, effective October 1, 2011. |
4. | Environmental Commitments and Contingencies |
We are subject to federal, state and local laws and regulations governing environmental quality
and pollution control. These laws and regulations require us to remove or remedy at current and
former operating sites the effect on the environment of the disposal or release of specified
substances. |
We have participated in the investigation, assessment or remediation, and have certain exposures
at six former Manufactured Gas Plant (MGP) sites. Those sites are located in Salisbury,
Maryland, and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have
also been in discussions with the Maryland Department of the Environment (MDE) regarding a
seventh former MGP site located in Cambridge, Maryland. |
As of September 30, 2011, we had approximately $11.1 million in environmental liabilities
related to all of FPUs MGP sites in Florida, which include the Key West, Pensacola, Sanford and
West Palm Beach sites, representing our estimate of the future costs associated with those
sites. FPU has approval to recover up to $14.0 million of its environmental costs related to
all of its MGP sites from insurance and from customers through rates. Approximately $8.2
million of FPUs expected environmental costs have been recovered from insurance and customers
through rates as of September 30, 2011. We also had approximately $5.8 million in regulatory
assets for future recovery of environmental costs from FPUs customers. |
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West Palm Beach, Florida |
Remedial options are being evaluated to respond to environmental impacts to soil and
groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West
Palm Beach, Florida, where FPU previously operated an MGP. Pursuant to a Consent Order
between FPU and the Florida Department of Environmental Protection (FDEP), effective April
8, 1991, FPU is required to complete the delineation of soil and groundwater impacts at the
site, and implement an effective remedy. |
On June 30, 2008, FPU transmitted to the FDEP a revised feasibility study, evaluating
appropriate remedies for the site. This revised feasibility study evaluated a wide range of
remedial alternatives based on criteria provided by applicable laws and regulations. On
April 30, 2009, the FDEP issued a remedial action order, which it subsequently withdrew. In
response to the Order and as a condition to its withdrawal, FPU
committed to perform additional field work in 2009 and complete an additional engineering
evaluation of certain remedial alternatives. The scope of this work has increased in
response to FDEPs requests for additional information. |
FPU performed additional field work in August 2010, which included the installation of
additional groundwater monitoring wells and performance of a comprehensive groundwater
sampling event. FPU also performed vapor intrusion sampling in October 2010. The results
of the field work were submitted to FDEP for their review and comment in October 2010. On
November 4, 2010, FDEP issued its comments on the feasibility study and the proposed remedy. |
On November 16, 2010, FPU presented to FDEP a new remedial action plan for the site, and
FDEP agreed with FPUs proposal to implement a phased approach to remediation. On December
22, 2010, FPU submitted to FDEP an interim Remedial Action Plan (RAP) to remediate the
east parcel of the site, which FDEP conditionally approved on February 4, 2011. Subsequent
modifications to the interim RAP, dated March 12, 2011 and April 18, 2011, were submitted to
address potential concerns raised by FDEP. An Approval Order for the interim RAP was issued
by FDEP on May 2, 2011, and subsequently modified by FDEP on May 18, 2011. |
FPU is currently implementing the interim RAP for the east parcel of the West Palm Beach
site, including the incorporation of FDEPs conditions for approval. The operations on the
east parcel have been relocated, and the structures removed. New monitoring wells and Air
Sparging and Soil-Vapor Extraction (AS/SVE) test wells were installed on the east parcel
in May 2011. The initial round of SVE and sparging pilot testing was conducted in June 2011,
and a subsequent round of testing was conducted in July of 2011. A supplement to the interim
RAP is being prepared to present to FDEP the findings of the pilot testing and proposed
design details for a full-scale remediation system. |
Estimated costs of remediation for the West Palm Beach site range from approximately $4.7
million to $15.8 million. We have revised our estimated maximum
cost of $13.1 million to $15.8 million to include costs associated with
relocation of FPUs operations at this site, which may be necessary to implement the
remedial plan, and any potential costs associated with future redevelopment of the
properties. |
We continue to expect that all costs related to these activities will be recoverable from
customers through rates. |
Sanford, Florida |
FPU is the current owner of property in Sanford, Florida, which was a former MGP site that
was operated by several other entities before FPU acquired the property. FPU was never an
owner or an operator of the MGP. In late September 2006, the United States Environmental
Protection Agency (EPA) sent a Special Notice Letter, notifying FPU, and the other
responsible parties at the site (Florida Power Corporation, Florida Power & Light Company,
Atlanta Gas Light Company, and the city of Sanford, Florida, collectively with FPU, the
Sanford Group), of EPAs selection of a final remedy for OU1 (soils), OU2 (groundwater),
and OU3 (sediments) for the site. The EPA projected the total estimated remediation costs
for this site to be approximately $12.9 million. |
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In January 2007, FPU and other members of the Sanford Group signed a Third Participation
Agreement, which provides for funding the final remedy approved by EPA for the site. FPUs
share of remediation costs under the Third Participation Agreement is set at five percent of
a maximum of $13 million, or $650,000. As of September 30, 2011, FPU has paid $650,000 to
the Sanford Group escrow account for its share of the funding requirements. |
The Sanford Group, EPA and the U.S. Department of Justice agreed to a Consent Decree in
March 2008, which was entered by the Federal Court in Orlando, Florida on January 15, 2009.
The Consent Decree
obligates the Sanford Group to implement the remedy approved by EPA for the site. The total
cost of the final remedy is now estimated at approximately $18 million. FPU has advised the
other members of the Sanford Group that it is unwilling at this time to agree to pay any sum
in excess of the $650,000 committed by FPU in the Third Participation Agreement. |
Several members of the Sanford Group have concluded negotiations with two adjacent property
owners to resolve damages that the property owners allege they have and will incur as a
result of the implementation of the EPA-approved remediation. In settlement of these
claims, members of the Sanford Group, which in this instance does not include FPU, have
agreed to pay specified sums of money to the parties. FPU has refused to participate in the
funding of the third-party settlement agreements based on its contention that it did not
contribute to the release of hazardous substances at the site giving rise to the third-party
claims. |
As of September 30, 2011, FPUs remaining share of remediation expenses, including
attorneys fees and costs, is estimated to be $24,000. However, we are unable to determine,
to a reasonable degree of certainty, whether the other members of the Sanford Group will
accept FPUs asserted defense to liability for costs exceeding $13.0 million to implement
the final remedy for this site or will pursue a claim against FPU for a sum in excess of the
$650,000 that FPU has paid under the Third Participation Agreement. No such claims have been
made as of September 30, 2011. |
Key West, Florida |
FPU formerly owned and operated an MGP in Key West, Florida. Field investigations performed
in the 1990s identified limited environmental impacts at the site, which is currently owned
by an unrelated third party. In September 2010, FDEP issued a Preliminary Contamination
Assessment Report, for additional soil and groundwater investigation work that was
undertaken by FDEP in November 2009 and January 2010, after 17 years of regulatory
inactivity. Because FDEP observed that some soil and groundwater standards were exceeded,
FDEP is requesting implementation of additional fieldwork which FDEP believes is warranted
for the site. |
FPU and the current site owner have had several discussions regarding the approach to be
taken with FDEP and the proposed scope of work. Representatives of FPU, FDEP and the
current site owner participated in a teleconference on July 7, 2011. During that call, the
scope of work was tentatively agreed upon, and FDEP agreed to proceed without using a
consent order. FPU and the current site owner submitted a work plan and schedule to FDEP on
September 30, 2011. Potential costs for investigation and remediation are projected to be
$118,000. |
Pensacola, Florida |
FPU formerly owned and operated an MGP in Pensacola, Florida, which was subsequently owned
by Gulf Power. Portions of the site are now owned by the City of Pensacola and the Florida
Department of Transportation (FDOT). In October 2009, FDEP informed Gulf Power that FDEP
would approve a conditional No Further Action (NFA) determination for the site, which must
include a requirement for institutional and engineering controls. On November 9, 2010, an
NFA Proposal was submitted to FDEP, along with a draft restrictive covenant for that portion
of the property currently owned by FDOT. FPU, FDOT and the City of Pensacola are working
together to obtain a restrictive covenant that is acceptable to FDEP to complete closure of
the site, and it is anticipated that no further monitoring will be required on the site.
FPUs total remaining consulting and remediation costs for this site are projected to be
$7,000. |
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In addition, we had $284,000 in environmental liabilities at September 30, 2011, related to
Chesapeakes MGP sites in Maryland and Florida, representing our estimate of future costs
associated with these sites. As of September 30, 2011, we had approximately $1.1 million in
regulatory and other assets for future recovery through rates. The following discussion
provides details on MGP sites for Chesapeakes Maryland and Florida divisions: |
Salisbury, Maryland |
We have substantially completed remediation of a site in Salisbury, Maryland, where it was
determined that a former MGP caused localized ground-water contamination. During 1996, we
completed construction of an AS/SVE system and began remediation procedures. We have
reported the remediation and monitoring results to the MDE on an ongoing basis since 1996.
In February 2002, the MDE granted permission to permanently decommission the AS/SVE system
and to discontinue all on-site and off-site well monitoring, except for one well, which is
being maintained for periodic product monitoring and recovery. |
Through September 30, 2011, we have incurred and paid approximately $2.9 million for
remedial actions and environmental studies related to this site. We have recovered
approximately $2.3 million through insurance proceeds or in rates, and $580,000 is expected
to be recovered through future rates. |
Winter Haven, Florida |
The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven,
Florida. Pursuant to a Consent Order entered into with the FDEP, we are obligated to assess
and remediate environmental impacts at this former MGP site. In 2001, FDEP approved a RAP
requiring construction and operation of a Bio-Sparging and Soil/Vapor Extraction (BS/SVE)
treatment system to address soil and groundwater impacts at a portion of the site. The
BS/SVE treatment system has been in operation since October 2002. Modifications and
upgrades to the BS/SVE treatment system were completed in October 2009. The Seventeenth
Semi-Annual RAP Implementation Status Report was submitted to FDEP in June 2011. The
groundwater sampling results through June 2011 show a continuing reduction in contaminant
concentrations and indicate that the recent treatment system modifications and upgrades have
had a beneficial impact on the rate of reduction. At present, we predict that remedial
action objectives could be met in approximately two to three years for the area being
treated by the BS/SVE treatment system. The total expected cost of operating and monitoring
the system is approximately $46,000. |
The BS/SVE treatment system at the Winter Haven site does not address impacted soils in the
southwest corner of the site. On April 16, 2010, a soil excavation interim RAP describing
the proposed excavation of approximately 4,000 cubic yards of impacted soils from the
southwest corner of the site was submitted to FDEP for review. On June 24, 2010, FDEP
provided comments on the soil excavation interim RAP by letter, to which we responded, and a
subsequent conditional approval letter was issued by FDEP on August 27, 2010. The cost to
implement this excavation plan has been estimated at $250,000; however, this estimate does
not include costs associated with dewatering or shoreline stabilization, which would be
required to complete the excavation. Because the costs associated with shoreline
stabilization and dewatering (including treatment and discharge of the pumped water) are
likely to be substantial, alternatives to this excavation plan are being evaluated. One
alternative currently being evaluated involves sparging into the southwest portion of the
property to treat soils rather than excavating the soils. Two new sparge points were
installed in the southwest portion of the property in February of 2011. Sparging into these
points has been initiated and operational and monitoring data over the next few quarters
should provide the information needed to make this evaluation. |
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FDEP has indicated that we may be required to remediate sediments along the shoreline of
Lake Shipp, immediately west of the site. Based on studies performed to date, we object to
FDEPs suggestion that the sediments have been adversely impacted by the former operations
of the MGP. Our early estimates indicate that some of the corrective measures discussed by
FDEP could cost as much as $1.0 million. We believe that corrective measures for the
sediments are not warranted and intend to oppose any requirement that we undertake
corrective measures in the offshore sediments. We have not recorded a liability for sediment
remediation, as the final resolution of this matter cannot be predicted at this time. |
Through September 30, 2011, we have incurred and paid approximately $1.7 million for
remedial activities at this site, and we have estimated and accrued for additional future
costs of $284,000. We have recovered through rates $1.5 million of the costs to remediate
the Winter Haven site and continue to expect that the
remaining $481,000, which is included in regulatory assets, will be recoverable from
customers through our approved rates. |
Other |
We are in discussions with the MDE regarding a former MGP site located in Cambridge,
Maryland. The outcome of this matter cannot be determined at this time; therefore, we have
not recorded an environmental liability for this location. |
5. | Other Commitments and Contingencies |
Litigation |
In May 2010, an FPU propane customer filed a class action complaint against FPU in Palm
Beach County, Florida, alleging, among other things, that FPU acted in a deceptive and
unfair manner related to a particular charge by FPU on its bills to propane customers and
the description of such charge. The suit sought to certify a class comprised of FPU propane
customers to whom such charge was assessed since May 2006 and requested damages and
statutory remedies based on the amounts paid by FPU customers for such charge. FPU
vigorously denied any wrongdoing and maintained that the particular charge at issue is
customary, proper and fair. Without admitting any wrongdoing, validity of the claims or a
properly certifiable class for the complaint, FPU entered into a settlement agreement with
the plaintiff in September 2010 to avoid the burden and expense of continued litigation. The
court approved the final settlement agreement, and the judgment became final on March 13,
2011. In 2010, we recorded $1.2 million of the total estimated costs related to this
litigation. Pursuant to the final settlement agreement, the distribution to the class was
made by May 13, 2011. |
On March 2, 2011, the City of Marianna, Florida filed a complaint against FPU in the Circuit
Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida. In the
complaint, the City of Marianna alleged three breaches of the
Franchise Agreement by FPU: (i) FPU failed to develop and implement TOU and
interruptible rates that were mutually agreed to by the City of Marianna and FPU; (ii)
mutually agreed upon TOU and interruptible rates by FPU were not effective or in effect by
February 17, 2011; and (iii) FPU did not have such rates available to all of FPUs customers
located within and without the corporate limits of the City of Marianna. The City of
Marianna is seeking a declaratory judgment allowing it to exercise its option under the
Franchise Agreement to purchase FPUs property (consisting of the electric distribution
assets) within the City of Marianna. Any such purchase would be subject to approval by the
Marianna Commission, which would also need to approve the presentation of a referendum to
voters in the City of Marianna related to the purchase and the operation by the City of
Marianna of an electric distribution facility. If the purchase is approved by the Marianna
Commission and the referendum is approved by the voters, the closing of the purchase must
occur within 12 months after the referendum is approved. On March 28, 2011, FPU filed its
answer to the declaratory action by the City of Marianna, in which it denied the material
allegations by the City of Marianna and asserted several affirmative defenses. The
litigation remains pending and discovery is still underway. On August 3, 2011, the City of
Marianna notified FPU that it was formally exercising its option to purchase FPUs property.
On August 31, 2011, FPU advised the City of Marianna that it has no right to exercise the
purchase option under the Franchise Agreement and that FPU would continue to oppose the
effort by the City of Marianna to purchase FPUs property. FPU intends to continue its
vigorous defense of the lawsuit filed by the City of Marianna and intends to oppose the
adoption of any proposed referendum to approve the purchase of the FPU property in the City
of Marianna. |
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Natural Gas, Electric and Propane Supply |
Our natural gas, electric and propane distribution operations have entered into contractual
commitments to purchase gas, electricity and propane from various suppliers. The contracts
have various expiration dates. We have a contract with an energy marketing and risk
management company to manage a portion of our natural gas transportation and storage
capacity. This contract expires on March 31, 2013. |
Chesapeakes Florida natural gas distribution division has firm transportation service
contracts with Florida Gas Transmission Company (FGT) and Gulfstream Natural Gas System,
LLC (Gulfstream). Pursuant to a capacity release program approved by the Florida PSC, all
of the capacity under these agreements has been released to various third parties, including
PESCO. Under the terms of these capacity release agreements, Chesapeake is contingently
liable to FGT and Gulfstream, should any party that acquired the capacity through release
fail to pay for the service. |
In May 2011, PESCO renewed contracts to purchase natural gas from various suppliers. These
contracts expire in May 2012. |
As discussed in Note 3 Rates and Other Regulatory Activities, on January 25, 2011, FPU
entered into an amendment to its Generation Services Agreement with Gulf Power, which
reduces the capacity demand quantity and provides the savings necessary to support the TOU
and interruptible rates for the customers in the City of Marianna, both of which were
approved by the Florida PSC. The amendment also extends the current agreement by two years,
with a new expiration date of December 31, 2019. |
FPUs electric fuel supply contracts require FPU to maintain an acceptable standard of
creditworthiness based on specific financial ratios. FPUs agreement with JEA requires FPU
to comply with the following ratios based on the results of the prior 12 months: (a) total
liabilities to tangible net worth less than 3.75 times, and (b) fixed charge coverage ratio
greater than 1.5 times. If either ratio is not met by FPU, it has 30 days to cure the
default or provide an irrevocable letter of credit if the default is not cured. FPUs
electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios
based on the average of the prior six quarters: (a) funds from operations interest coverage
ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If
FPU fails to meet the requirements, it has to provide the supplier a written explanation of
actions taken or proposed to be taken to become compliant. Failure to comply with the
ratios specified in the Gulf Power agreement could result in FPU providing an irrevocable
letter of credit. As of September 30, 2011, FPU was in compliance with all of the
requirements of its fuel supply contracts. |
Corporate Guarantees |
The Board of Directors has previously authorized the Company to issue up to $35 million of
corporate guarantees or letters of credit on behalf of our subsidiaries. On March 2, 2011,
the Board increased this limit from $35 million to $45 million. |
We have issued corporate guarantees to certain vendors of our subsidiaries, the largest
portion of which are for our propane wholesale marketing subsidiary and our natural gas
marketing subsidiary. These corporate guarantees provide for the payment of propane and
natural gas purchases in the event of the respective subsidiarys default. Neither
subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for
these purchases are recorded in our financial statements when incurred. The aggregate
amount guaranteed at September 30, 2011 was $26.7 million, with the guarantees expiring on
various dates through December 2012. |
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Chesapeake guarantees the payment of FPUs first mortgage bonds. The maximum exposure under
the guarantee is the outstanding principal and accrued interest balances. The outstanding
principal balances of FPUs first mortgage bonds approximate their carrying values (see Note
12, Long-Term Debt, to the unaudited condensed consolidated financial statements for
further details). |
In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million,
which expires on September 12, 2012, related to the electric transmission services for FPUs
northwest electric division. We have also issued a letter of credit to our current primary
insurance company for $656,000, which expires on December 2, 2011, as security to
satisfy the deductibles under our various outstanding insurance policies. As a result of a
change in our primary insurance company in 2010, we renewed the letter of credit
for $725,000 to our former primary insurance company, which will expire on June 1, 2012.
There have been no draws on these letters of credit as of September 30, 2011. We do not
anticipate that the letters of credit will be drawn upon by the counterparties, and we
expect that the letters of credit will be renewed to the extent necessary in the future. |
We provided a letter of credit for $2.5 million to TETLP related to the Precedent Agreement,
which is further described below. |
Agreements for Access to New Natural Gas Supplies |
On April 8, 2010, our Delaware and Maryland divisions entered into a Precedent Agreement
with TETLP to secure firm transportation service from TETLP in conjunction with its new
expansion project, which is expected to expand TETLPs mainline system by up to 190,000
Dts/d. The Precedent Agreement provides that, upon satisfaction of certain conditions, the
parties will execute two firm transportation service contracts, one for our Delaware
division and one for our Maryland division, for 34,100 and 15,900 Dts/d, respectively,
including the additional volume subscribed in a subsequent agreement, to be effective on the
service commencement date of the project, which is currently projected to occur in November
2012. Each firm transportation service contract shall, among other things, provide for: (a)
the maximum daily quantity of Dts/d described above; (b) a term of 15 years; (c) a receipt
point at Clarington, Ohio; (d) a delivery point at Honey Brook, Pennsylvania; and (e)
certain credit standards and requirements for security. Commencement of service and TETLPs
and our rights and obligations under the two firm transportation service contracts are
subject to satisfaction of various conditions specified in the Precedent Agreement. |
Our Delmarva natural gas supplies are currently received primarily from the Gulf of Mexico
natural gas production region and are transported through three interstate upstream
pipelines, two of which interconnect directly with Eastern Shores transmission system. The
new firm transportation service contracts between our Delaware and Maryland divisions and
TETLP will provide an additional direct interconnection with Eastern Shores transmission
system and access to new sources of natural gas supplies from other natural gas production
regions, including the Appalachian production region, thereby providing increased
reliability and diversity of supply. They will also provide our Delaware and Maryland
divisions with additional upstream transportation capacity to meet current customer demands
and to plan for sustainable growth. |
The Precedent Agreement provides that the parties shall promptly meet and work in good faith
to negotiate a mutually acceptable reservation rate. Failure to agree upon a mutually
acceptable reservation rate would have enabled either party to terminate the Precedent
Agreement, and would have subjected us to reimburse TETLP for certain pre-construction
costs; however, on July 2, 2010, our Delaware and Maryland divisions executed the required
reservation rate agreements with TETLP. |
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The Precedent Agreement requires us to reimburse TETLP for our proportionate share of
TETLPs pre-service costs incurred to date, if we terminate the Precedent Agreement, are
unwilling or unable to perform our material duties and obligations thereunder, or take
certain other actions whereby TETLP is unable to obtain the authorizations and exemptions
required for this project. If such termination were to occur, we estimate that our
proportionate share of TETLPs pre-service costs could be approximately $3.8 million as of
September 30, 2011. If we were to terminate the Precedent Agreement after TETLP completed
its construction of all facilities, which is expected to be in the fourth quarter of 2012,
our proportionate share could be as much as approximately $50 million. The actual amount of
our proportionate share of such costs could differ significantly and would ultimately be
based on the level of pre-service costs at the time of any potential termination. As our
Delaware and Maryland divisions have now executed the required reservation rate agreements
with TETLP, we believe that the likelihood of terminating the Precedent Agreement and having
to reimburse TETLP for our proportionate share of TETLPs pre-service costs is remote. |
As previously mentioned, we have provided a letter of credit to TETLP for $2.5 million,
which is the maximum amount required under the Precedent Agreement with TETLP. |
On March 17, 2010, our Delaware and Maryland divisions entered into a separate Precedent
Agreement with Eastern Shore to extend its mainline by eight miles to interconnect with
TETLP at Honey Brook, Pennsylvania. As discussed in Note 3, Rates and Other Regulatory
Activities, to the unaudited condensed consolidated financial statements, Eastern Shore
completed the extension project in December 2010 and commenced the service in January 2011.
The rate for the transportation service on this extension is Eastern Shores current tariff
rate for service in that area. |
TETLP is proceeding with obtaining the necessary approvals, authorizations or exemptions for
construction and operation of its portion of the project, including, but not limited to,
approval by the FERC. TETLP is expecting the FERC approval by the end of 2011. Our
Delaware and Maryland divisions require no regulatory approvals or exemptions to receive
transmission service from TETLP or Eastern Shore. |
As the Eastern Shore and TETLP firm transportation services commence, our Delaware and
Maryland divisions incur costs for those services based on the agreed and FERC-approved
reservation rates, which will become an integral component of the costs associated with
providing natural gas supplies to our Delaware and Maryland divisions and will be included
in the annual GSR filings for each of our respective divisions. |
Non-income-based Taxes |
From time to time, we are subject to various audits and reviews by the states and other
regulatory authorities regarding non-income-based taxes. We are currently undergoing a
sales tax audit in Florida. As of September 30, 2011, we maintained an accrual of $578,000
related to additional sales taxes and gross receipts taxes owed to various states, all of
which were recorded in 2010. |
Other Contingency |
As of September 30, 2011, we maintained a $750,000 accrual, which was recorded in 2010 based
on managements assessment of FPUs earnings and regulatory risk to its earnings associated
with possible Florida PSC action related to our requested recovery and the matters set forth
in the Come-Back filing (See Note 3, Rates and Other Regulatory Activities, to the
unaudited condensed consolidated financial statements for further discussion).
|
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6. | Segment Information |
We use the management approach to identify operating segments. We organize our business
around differences in regulatory environment and/or products or services, and the operating
results of each segment are regularly reviewed by the chief operating decision maker (our
Chief Executive Officer) in order to make decisions about resources and to assess
performance. The segments are evaluated based on their pre-tax operating income. Our
operations comprise three operating segments: |
| Regulated Energy. The regulated energy segment includes natural gas
distribution, electric distribution and natural gas transmission operations. All
operations in this segment are regulated, as to their rates and services, by the
PSC having jurisdiction in each operating territory or by the FERC in the case of
Eastern Shore. |
| Unregulated Energy. The unregulated energy segment includes natural gas
marketing, propane distribution and propane wholesale marketing operations, which
are unregulated as to their rates and charges for their services. |
| Other. The other segment consists primarily of the advanced information
services operation, unregulated subsidiaries that own real estate leased to
Chesapeake and certain corporate costs not allocated to other operations. |
The following table presents information about our reportable segments. |
Three Months Ended | Nine Months Ended | |||||||||||||||
For the Perionds Ended September 30, | 2011 | 2010 | 2011 | 2010 | ||||||||||||
(in thousands) | ||||||||||||||||
Operating Revenues, Unaffiliated Customers |
||||||||||||||||
Regulated Energy |
$ | 53,435 | $ | 53,112 | $ | 192,130 | $ | 196,957 | ||||||||
Unregulated Energy |
23,720 | 20,134 | 112,163 | 103,654 | ||||||||||||
Other |
3,455 | 3,220 | 9,746 | 9,176 | ||||||||||||
Total operating revenues, unaffiliated
customers |
$ | 80,610 | $ | 76,466 | $ | 314,039 | $ | 309,787 | ||||||||
Intersegment Revenues (1) |
||||||||||||||||
Regulated Energy |
$ | 354 | $ | 300 | $ | 988 | $ | 822 | ||||||||
Unregulated Energy |
1 | | 1 | 364 | ||||||||||||
Other |
196 | 197 | 586 | 644 | ||||||||||||
Total intersegment revenues |
$ | 551 | $ | 497 | $ | 1,575 | $ | 1,830 | ||||||||
Operating Income (Loss) |
||||||||||||||||
Regulated Energy |
$ | 7,023 | $ | 6,536 | $ | 31,194 | $ | 32,360 | ||||||||
Unregulated Energy |
(1,472 | ) | (2,237 | ) | 7,047 | 4,732 | ||||||||||
Other and eliminations |
43 | 284 | (32 | ) | 650 | |||||||||||
Total operating income |
5,594 | 4,583 | 38,209 | 37,742 | ||||||||||||
Other income, net of other expenses |
649 | 102 | 699 | 206 | ||||||||||||
Interest |
2,389 | 2,256 | 6,654 | 6,924 | ||||||||||||
Income taxes |
1,457 | 801 | 12,590 | 12,082 | ||||||||||||
Net income |
$ | 2,397 | $ | 1,628 | $ | 19,664 | $ | 18,942 | ||||||||
(1) | All significant intersegment revenues are billed at market rates and have been
eliminated
from consolidated operating revenues. |
September 30, | December 31, | |||||||
(in thousands) | 2011 | 2010 | ||||||
Identifiable Assets |
||||||||
Regulated energy |
$ | 528,492 | $ | 520,192 | ||||
Unregulated energy |
96,760 | 113,039 | ||||||
Other |
32,264 | 37,762 | ||||||
Total identifiable assets |
$ | 657,516 | $ | 670,993 | ||||
Our operations are almost entirely domestic. Our advanced information services
subsidiary, BravePoint, has infrequent transactions in foreign countries, primarily Canada,
which are denominated and paid in U.S. dollars. These transactions are immaterial to the
consolidated revenues. |
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7. | Employee Benefit Plans |
Net periodic benefit costs for our pension and post-retirement benefits plans for the three and
nine months ended September 30, 2011 and 2010 are set forth in the following table: |
Chesapeake | ||||||||||||||||||||||||||||||||||||||||
Chesapeake | FPU | Chesapeake | Postretirement | FPU | ||||||||||||||||||||||||||||||||||||
(in thousands) | Pension Plan | Pension Plan | SERP | Plan | Medical Plan | |||||||||||||||||||||||||||||||||||
For the Three Months Ended September 30, | 2011 | 2010 | 2011 | 2010 | 2011 | 2010 | 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||||||||||||
Service Cost |
$ | | $ | | $ | | $ | | $ | | $ | | $ | | $ | | $ | 26 | $ | 28 | ||||||||||||||||||||
Interest Cost |
130 | 147 | 671 | 638 | 26 | 35 | 14 | 30 | 38 | 33 | ||||||||||||||||||||||||||||||
Expected return on plan assets |
(100 | ) | (108 | ) | (683 | ) | (618 | ) | | | | | | | ||||||||||||||||||||||||||
Amortization of prior service cost |
(1 | ) | (1 | ) | | | 4 | 5 | | | | | ||||||||||||||||||||||||||||
Amortization of net loss |
39 | 40 | | | 10 | 15 | | 15 | 5 | | ||||||||||||||||||||||||||||||
Net periodic cost (benefit) |
68 | 78 | (12 | ) | 20 | 40 | 55 | 14 | 45 | 69 | 61 | |||||||||||||||||||||||||||||
Settlement expense |
| | | | 219 | | | | | | ||||||||||||||||||||||||||||||
Amortization of pre-merger regulatory asset |
| | 190 | 191 | | | | | 2 | 2 | ||||||||||||||||||||||||||||||
Total periodic cost |
$ | 68 | $ | 78 | $ | 178 | $ | 211 | $ | 259 | $ | 55 | $ | 14 | $ | 45 | $ | 71 | $ | 63 | ||||||||||||||||||||
Chesapeake | ||||||||||||||||||||||||||||||||||||||||
Chesapeake | FPU | Chesapeake | Postretirement | FPU | ||||||||||||||||||||||||||||||||||||
(in thousands) | Pension Plan | Pension Plan | SERP | Plan | Medical Plan | |||||||||||||||||||||||||||||||||||
For the Nine Months Ended September 30, | 2011 | 2010 | 2011 | 2010 | 2011 | 2010 | 2011 | 2010 | 2011 | 2010 | ||||||||||||||||||||||||||||||
Service Cost |
$ | | $ | | $ | | $ | | $ | | $ | | $ | | $ | | $ | 79 | $ | 83 | ||||||||||||||||||||
Interest Cost |
390 | 441 | 2,014 | 1,913 | 80 | 105 | 44 | 91 | 116 | 101 | ||||||||||||||||||||||||||||||
Expected return on plan assets |
(302 | ) | (323 | ) | (2,051 | ) | (1,856 | ) | | | | | | | ||||||||||||||||||||||||||
Amortization of prior service cost |
(4 | ) | (4 | ) | | | 14 | 15 | | | | | ||||||||||||||||||||||||||||
Amortization of net loss |
117 | 119 | | | 29 | 45 | | 44 | 15 | | ||||||||||||||||||||||||||||||
Net periodic cost (benefit) |
201 | 233 | (37 | ) | 57 | 123 | 165 | 44 | 135 | 210 | 184 | |||||||||||||||||||||||||||||
Settlement expense |
217 | | | | 219 | | | | | | ||||||||||||||||||||||||||||||
Amortization of pre-merger regulatory asset |
| | 571 | 698 | | | | | 6 | 6 | ||||||||||||||||||||||||||||||
Total periodic cost |
$ | 418 | $ | 233 | $ | 534 | $ | 755 | $ | 342 | $ | 165 | $ | 44 | $ | 135 | $ | 216 | $ | 190 | ||||||||||||||||||||
We expect to record pension and postretirement benefit costs of approximately $1.9 million
for 2011. Included in that amount is a pension settlement expense of $217,000 recorded during
the first nine months of 2011 related to a lump-sum pension distribution of $844,000 from the
Chesapeake Pension Plan in January 2011 and $219,000 of settlement expense in July 2011 related
to a lump-sum distribution of $765,000 from the Chesapeake SERP. Also included in the $1.9
million pension and postretirement benefit costs for 2011 is $769,000 related to continued
amortization of the FPU pension regulatory asset, which represents the portion attributable to
FPUs regulated energy operations of the changes in funded status that occurred but were not
recognized as part of net periodic benefit costs prior to the merger. This was deferred as a
regulatory asset by FPU prior to the merger to be recovered through rates pursuant to a previous
order by the Florida PSC. The unamortized balance of this regulatory asset was $6.1 million and
$6.7 million at September 30, 2011 and December 31, 2010, respectively. |
During the three and nine months ended September 30, 2011, we contributed $818,000 and $885,000,
respectively, to the Chesapeake Pension Plan. We also contributed $466,000 and $1.0 million to
the FPU Pension Plan during the three and nine months ended September 30, 2011, respectively. We
expect to contribute $1.0 million and $1.3 million to the Chesapeake and FPU Pension Plans,
respectively, during the year 2011. |
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The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded
and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake
SERP for the three and nine months ended September 30, 2011, were $22,000 and $67,000,
respectively; for the year 2011, such benefits paid are expected to be approximately $853,000,
which includes the lump-sum distribution of $765,000 as mentioned above. Cash benefits paid for
the Chesapeake Postretirement Plan, primarily for medical claims for the three and nine months
ended September 30, 2011, totaled $22,000 and $68,000, respectively; for the year 2011, we have
estimated that approximately $96,000 will be paid for such benefits. Cash benefits paid for the
FPU Medical Plan, primarily for medical claims for the three and nine months ended September 30,
2011, totaled $72,000 and $107,000, respectively; for the year 2011, we have estimated that
approximately $158,000 will be paid for such benefits. |
In connection with the lump-sum pension distribution from the Chesapeake Pension Plan in January
2011 and the Chesapeake SERP in July 2011, and related settlement accounting, we re-measured the
assets and obligations of the Chesapeake Pension Plan and the Chesapeake SERP. The assumptions
used for the discount rate to calculate the benefit obligation remained unchanged at five
percent. The average expected return on plan assets also did not change and remained at six
percent. |
8. | Investments |
The investment balance at September 30, 2011, represents: (a) a Rabbi Trust associated with our
Supplemental Executive Retirement Savings Plan, (b) a Rabbi Trust related to a stay bonus
agreement with a former executive, and (c) investments in equity securities. We classify these
investments as trading securities and report them at their fair value. Any unrealized gains and
losses, net of other expenses, are included in other income in the condensed consolidated
statements of income. We also have recorded an associated liability that is adjusted each month
for the gains and losses incurred by the Rabbi Trusts. At September 30, 2011 and December 31,
2010, total investments had a fair value of $3.7 million and $4.0 million, respectively. |
9. | Share-Based Compensation |
Our non-employee directors and key employees are awarded share-based awards through our
Directors Stock Compensation Plan (DSCP) and the Performance Incentive Plan (PIP),
respectively. We record these share-based awards as compensation costs over the respective
service period for which services are received in exchange for an award of equity or
equity-based compensation. The compensation cost is primarily based on the fair value of the
grant on the date it was awarded. |
The table below presents the amounts included in net income related to share-based compensation
expense for the awards granted under the DSCP and the PIP for the three and nine months ended
September 30, 2011 and 2010: |
Three Months Ended | Nine Months Ended | |||||||||||||||
For the Periods Ended September 30, | 2011 | 2010 | 2011 | 2010 | ||||||||||||
(in thousands) | ||||||||||||||||
Directors Stock Compensation Plan |
$ | 111 | $ | 74 | $ | 296 | $ | 209 | ||||||||
Performance Incentive Plan |
262 | 213 | 782 | 690 | ||||||||||||
Total compensation expense |
373 | 287 | 1,078 | 899 | ||||||||||||
Less: tax benefit |
150 | 115 | 432 | 361 | ||||||||||||
Share-Based Compensation amounts
included in net income |
$ | 223 | $ | 172 | $ | 646 | $ | 538 | ||||||||
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Directors Stock Compensation Plan |
Shares granted under the DSCP are issued in advance of the directors service periods and are
fully vested as of the date of the grant. We record a prepaid expense of the shares issued and
amortize the expense equally over a
service period of one year. In May 2011, each of our non-employee directors received an annual
retainer of 900 shares of common stock under the DSCP. A summary of stock activity under the
DSCP during the nine months ended September 30, 2011 is presented below: |
Number of | Weighted Average | |||||||
Shares | Grant Date Fair Value | |||||||
Outstanding December 31, 2010 |
| | ||||||
Granted (1) |
11,104 | $ | 41.03 | |||||
Vested |
11,104 | $ | 41.03 | |||||
Forfeited |
| | ||||||
Outstanding September 30, 2011 |
| | ||||||
(1) | In January 2011, our former Chief Executive Officer John Schimkaitis, retired from
the Company and was awarded 304 shares of common stock for the prorated portion of his service
period as he began his service as a non-executive board member. |
At September 30, 2011, there was $258,000 of unrecognized compensation expense related to
the DSCP awards. This expense is expected to be recognized over the remaining directors
service periods ending as of the 2012 Annual Meeting. |
Performance Incentive Plan |
The table below presents the summary of the stock activity for the PIP for the nine months ended
September 30, 2011: |
Number of | Weighted Average | |||||||
Shares | Fair Value | |||||||
Outstanding December 31, 2010 |
101,150 | $ | 28.78 | |||||
Granted |
41,664 | 40.16 | ||||||
Vested |
31,400 | 27.63 | ||||||
Forfeited |
24,000 | 29.31 | ||||||
Expired |
| | ||||||
Outstanding September 30, 2011 |
87,414 | $ | 34.47 | |||||
In January 2011, the Board of Directors granted awards under the PIP for 41,664 shares.
The shares granted in January 2011 are multi-year awards, of which 10,500 shares will vest at
the end of the two-year service period, or December 31, 2012. The remaining 31,164 shares will
vest at the end of the three-year service period, or December 31, 2013. These awards are earned
based upon the successful achievement of long-term goals, growth and financial results, which
comprised both market-based and performance-based conditions or targets. The fair value of each
performance-based condition or target is equal to the market price of our common stock on the
date of the grant. For the market-based conditions, we used the Black-Scholes pricing model to
estimate the fair value of each market-based award granted. |
In conjunction with his retirement, our former Chief Executive Officer forfeited 24,000 shares,
which represents the shares awarded under the PIP in January 2009 for the performance period
ending December 31, 2011 and in January 2010 for the performance period ending December 31,
2012, that had not vested. |
At September 30, 2011, the aggregate intrinsic value of the PIP awards was $1.9 million. |
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10. | Derivative Instruments |
We use derivative and non-derivative contracts to engage in trading activities and manage risks
related to obtaining adequate supplies and the price fluctuations of natural gas, electricity
and propane. Our natural gas, electric and propane distribution operations have entered into
agreements with suppliers to purchase natural gas, electricity and propane for resale to their
customers. Purchases under these contracts either do not meet the definition of derivatives or
are considered normal purchases and sales and are accounted for on an accrual basis. Our
propane distribution operation may also enter into fair value hedges of its inventory in order
to mitigate the impact of wholesale price fluctuations. As of September 30, 2011, our natural
gas and electric distribution operations did not have any outstanding derivative contracts. In
August 2011, our propane distribution operation entered into a put option to protect against the
decline in propane prices and related potential inventory losses associated with 630,000 gallons
purchased for the propane price cap program in the upcoming heating season. This put option is
exercised if the propane prices fall below the strike price of $1.445 per gallon in January
through March of 2012 and we will receive the difference between the market price and the strike
price during those months. We paid $91,000 to purchase the put option. We account for this put
option as a fair value hedge. As of September 30, 2011, the put option had a fair value of
$92,000. The change in the fair value of the put option reduced our propane inventory balance. |
Xeron, our propane wholesale and marketing subsidiary, engages in trading activities using
forward and futures contracts. These contracts are considered derivatives and have been
accounted for using the mark-to-market method of accounting. Under the mark-to-market method of
accounting, the trading contracts are recorded at fair value, and the changes in fair value of
those contracts are recognized as unrealized gains or losses in the statement of income in the
period of change. As of September 30, 2011, we had the following outstanding trading contracts
which we accounted for as derivatives: |
Quantity in | Estimated Market | Weighted Average | ||||||||||
At September 30, 2011 | Gallons | Prices | Contract Prices | |||||||||
Forward Contracts |
||||||||||||
Sale |
21,361,200 | $ | 1.3900 $1.6200 | $ | 1.5231 | |||||||
Purchase |
21,193,200 | $ | 1.3344 $1.6047 | $ | 1.5149 | |||||||
Estimated market prices and weighted average contract prices are in dollars per gallon. |
All contracts expire during or prior to the first quarter of 2012. |
The following tables present information about the fair value and related gains and losses
of our derivative contracts. We did not have any derivative contracts with a
credit-risk-related contingency. |
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Fair values of the derivative contracts recorded in the condensed consolidated balance sheet as
of September 30, 2011 and December 31, 2010, are the following: |
Asset Derivatives | ||||||||||
Fair Value | ||||||||||
(in thousands) | Balance Sheet Location | September 30, 2011 | December 31, 2010 | |||||||
Derivatives not designated as hedging instruments | ||||||||||
Forward contracts |
Mark-to-market energy assets | $ | 1,137 | $ | 1,642 | |||||
Put option (1) |
Mark-to-market energy assets | | | |||||||
Derivatives designated as fair value hedges | ||||||||||
Put option (2) |
Mark-to-market energy assets | 92 | | |||||||
Total asset derivatives |
$ | 1,229 | $ | 1,642 | ||||||
Liability Derivatives | ||||||||||
Fair Value | ||||||||||
(in thousands) | Balance Sheet Location | September 30, 2011 | December 31, 2010 | |||||||
Derivatives not designated as hedging instruments | ||||||||||
Forward contracts |
Mark-to-market energy liabilities | $ | 956 | $ | 1,492 | |||||
Total liability derivatives |
$ | 956 | $ | 1,492 | ||||||
(1) | We purchased a put option for the Pro-Cap (propane price cap) Plan in
October 2010. The put option, which expired in January and February 2011,
had a fair value of $0 at December 31, 2010. |
|
(2) | We purchased a put option for the Pro-Cap Plan in August 2011. The
put option, which will expire during the first quarter of 2012, has a fair
value of $92 at September 30, 2011. |
The effects of gains and losses from derivative instruments on the condensed
consolidated financial statements are the following: |
Amount of Gain (Loss) on Derivatives: | ||||||||||||||||||
Location of Gain | For the Three Months Ended September 30, | For the Nine Months Ended September 30, | ||||||||||||||||
(in thousands) | (Loss) on Derivatives | 2011 | 2010 | 2011 | 2010 | |||||||||||||
Derivatives not designated as hedging instruments: | ||||||||||||||||||
Put Option(1) |
Cost of Sales | $ | | $ | | $ | | $ | | |||||||||
Unrealized gain on forward contracts |
Revenue | 62 | 69 | 32 | 443 | |||||||||||||
Derivatives designated as fair value hedges: | ||||||||||||||||||
Put
Option(2) |
Propane inventory | 1 | | 1 | | |||||||||||||
Total |
$ | 63 | $ | 69 | $ | 33 | $ | 443 | ||||||||||
(1) | We purchased a put option for the Pro-Cap Plan in October 2010.
The put option, which expired in January and February 2011, had a fair value
of $0 at December 31, 2010. |
|
(2) | We purchased a put option for the Pro-Cap Plan in August 2011. The
put option, which will expire during the first quarter of 2012, has a fair
value of $92 at September 30, 2011. |
The effects of trading activities on the condensed consolidated statements of income
are the following: |
Location in the | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||||
(in thousands) | Statement of Income | 2011 | 2010 | 2011 | 2010 | |||||||||||||
Realized gains on forward contracts |
Revenue | $ | 380 | $ | 271 | $ | 1,934 | $ | 1,010 | |||||||||
Changes in mark-to-market energy assets |
Revenue | 62 | 69 | 32 | 443 | |||||||||||||
Total |
$ | 442 | $ | 340 | $ | 1,966 | $ | 1,453 | ||||||||||
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11. | Fair Value of Financial Instruments |
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to
measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in
active markets for identical assets or liabilities (Level 1 measurements) and the lowest
priority to unobservable inputs (Level 3 measurements). The three levels of the fair value
hierarchy are the following: |
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement
date for identical, unrestricted assets or liabilities; |
Level 2: Quoted prices in markets that are not active, or inputs which are observable,
either directly or indirectly, for substantially the full term of the asset or liability;
and |
Level 3: Prices or valuation techniques requiring inputs that are both significant to the
fair value measurement and unobservable (i.e. supported by little or no market activity). |
The following table summarizes our financial assets and liabilities that are measured at fair
value on a recurring basis and the fair value measurements, by level, within the fair value
hierarchy used at September 30, 2011: |
Fair Value Measurements Using: | ||||||||||||||||
Significant Other | Significant | |||||||||||||||
Quoted Prices in | Observable | Unobservable | ||||||||||||||
Active Markets | Inputs | Inputs | ||||||||||||||
(in thousands) | Fair Value | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
Assets: |
||||||||||||||||
Investments equity securities |
$ | 1,937 | $ | 1,937 | $ | | $ | | ||||||||
Investments other |
$ | 1,751 | $ | 1,751 | $ | | $ | | ||||||||
Mark-to-market energy assets,
including put option |
$ | 1,229 | $ | | $ | 1,229 | $ | | ||||||||
Liabilities: |
||||||||||||||||
Mark-to-market energy
liabilities |
$ | 956 | $ | | $ | 956 | $ | |
The following table summarizes our financial assets and liabilities that are measured at fair
value on a recurring basis and the fair value measurements, by level, within the fair value
hierarchy used at December 31, 2010: |
Fair Value Measurements Using: | ||||||||||||||||
Significant Other | Significant | |||||||||||||||
Quoted Prices in | Observable | Unobservable | ||||||||||||||
Active Markets | Inputs | Inputs | ||||||||||||||
(in thousands) | Fair Value | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
Assets: |
||||||||||||||||
Investments equity securities |
$ | 1,515 | $ | 1,515 | $ | | $ | | ||||||||
Investments other |
$ | 2,521 | $ | 2,521 | $ | | $ | | ||||||||
Mark-to-market energy assets,
including put option |
$ | 1,642 | $ | | $ | 1,642 | $ | | ||||||||
Liabilities: |
||||||||||||||||
Mark-to-market energy
liabilities |
$ | 1,492 | $ | | $ | 1,492 | $ | |
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The following valuation techniques were used to measure fair value assets in the table above on
a recurring basis as of September 30, 2011 and December 31, 2010: |
Level 1 Fair Value Measurements: |
Investments- equity securities - The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities. |
Investments- other - The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares. |
Level 2 Fair Value Measurements: |
Mark-to-market energy assets and liabilities These forward contracts are valued using market transactions in either the listed or over the counter (OTC) markets. |
Propane put option The fair value of the propane put option is determined using market transactions for similar assets and liabilities in either the listed or OTC markets. |
At September 30, 2011, there were no non-financial assets or liabilities required to be
reported at fair value. We review our non-financial assets for impairment at least on an annual
basis, as required. |
Other Financial Assets and Liabilities |
Financial assets with carrying values approximating fair value include cash and cash equivalents
and accounts receivable. Financial liabilities with carrying values approximating fair value
include accounts payable and other accrued liabilities and short-term debt. The carrying value
of these financial assets and liabilities approximates fair value due to their short maturities
and because interest rates approximate current market rates for short-term debt. |
At September 30, 2011, long-term debt, which includes the current maturities of long-term debt,
had a carrying value of $126.3 million, compared to a fair value of $150.4 million, using a
discounted cash flow methodology that incorporates a market interest rate based on published
corporate borrowing rates for debt instruments with similar terms and average maturities, with
adjustments for duration, optionality, and risk profile. At December 31, 2010, long-term debt,
including the current maturities, had a carrying value of $98.9 million, compared to the
estimated fair value of $113.4 million. |
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12. | Long-Term Debt |
Our outstanding long-term debt is shown below: |
September 30, | December 31, | |||||||
(in thousands) | 2011 | 2010 | ||||||
FPU secured first mortgage bonds (A): |
||||||||
9.57% bond, due May 1, 2018 |
$ | 6,347 | $ | 7,248 | ||||
10.03% bond, due May 1, 2018 |
3,491 | 3,986 | ||||||
9.08% bond, due June 1, 2022 |
7,957 | 7,950 | ||||||
Uncollateralized senior notes: |
||||||||
6.85% note, due January 1, 2012 |
1,000 | 1,000 | ||||||
7.83% note, due January 1, 2015 |
8,000 | 8,000 | ||||||
6.64% note, due October 31, 2017 |
19,091 | 19,091 | ||||||
5.50% note, due October 12, 2020 |
20,000 | 20,000 | ||||||
5.93% note, due October 31, 2023 |
30,000 | 30,000 | ||||||
5.68% note, due June 30, 2026 |
29,000 | | ||||||
Convertible debentures: |
||||||||
8.25% due March 1, 2014 |
1,179 | 1,318 | ||||||
Promissory note |
200 | 265 | ||||||
Total long-term debt |
126,265 | 98,858 | ||||||
Less: current maturities |
(9,196 | ) | (9,216 | ) | ||||
Total long-term debt, net of current maturities |
$ | 117,069 | $ | 89,642 | ||||
(A) | FPU secured first mortgage bonds are guaranteed by Chesapeake. |
On June 23, 2011, we issued $29.0 million of 5.68 percent unsecured senior notes to
Metropolitan Life Insurance Company and New England Life Insurance Company, pursuant to an
agreement we entered into with them on June 29, 2010. These notes have similar covenants and
default provisions as Chesapeakes existing senior notes, and they require annual principal
payments of $2.9 million beginning in the sixth year after the issuance. We used the proceeds to
permanently finance the redemption of the 6.85 percent and 4.90 percent series of FPU first
mortgage bonds. These redemptions occurred in January 2010 and were previously financed by
Chesapeakes short-term loan facilities. Under the same agreement, we may issue an additional
$7.0 million of unsecured senior notes prior to May 3, 2013, at a rate ranging from 5.28 percent
to 6.43 percent based on the timing of the issuance. These notes, if issued, will have similar
covenants and default provisions as the senior notes issued in June 2011. |
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Item 2. | Managements Discussion and Analysis of Financial Condition and Results of Operations |
| state and federal legislative and regulatory initiatives that affect cost and
investment recovery, have an impact on rate structures, and affect the speed at and degree
to which competition enters the electric and natural gas industries (including
deregulation); |
| the outcomes of regulatory, tax, environmental and legal matters, including whether
pending matters are resolved within current estimates; |
| the loss of customers due to government mandated sale of our utility distribution
facilities; |
| industrial, commercial and residential growth or contraction in our service
territories; |
| the weather and other natural phenomena, including the economic, operational and other
effects of hurricanes and ice storms; |
| the timing and extent of changes in commodity prices and interest rates; |
| general economic conditions, including any potential effects arising from terrorist
attacks and any consequential hostilities or other hostilities or other external factors
over which we have no control; |
| changes in environmental and other laws and regulations to which we are subject; |
| the results of financing efforts, including our ability to obtain financing on
favorable terms, which can be affected by various factors, including credit ratings and
general economic conditions; |
| declines in the market prices of equity securities and resultant cash funding
requirements for our defined benefit pension plans; |
| the creditworthiness of counterparties with which we are engaged in transactions; |
| growth in opportunities for our business units; |
| the extent of success in connecting natural gas and electric supplies to transmission
systems and in expanding natural gas and electric markets; |
| the effect of accounting pronouncements issued periodically by accounting
standard-setting bodies; |
| conditions of the capital markets and equity markets during the periods covered by the
forward-looking statements; |
||
| the ability to successfully execute, manage and integrate merger, acquisition or
divestiture plans, regulatory or other limitations imposed as a result of a merger,
acquisition or divestiture, and the success of the business following a merger,
acquisition or divestiture; |
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| the ability to manage and maintain key customer relationships; |
| the ability to maintain key supply sources; |
| the effect of spot, forward and future market prices on our distribution, wholesale
marketing and energy trading businesses; |
| the effect of competition on our businesses; |
| the ability to construct facilities at or below estimated costs; |
| changes in technology affecting our advanced information services business; and |
| operation and litigation risks that may not be covered by insurance. |
| executing a capital investment program in pursuit of organic growth opportunities that
generate returns equal to or greater than our cost of capital; |
| expanding the regulated energy distribution and transmission businesses into new
geographic areas and providing new services in our current service territories; |
| expanding the propane distribution business in existing and new markets through
leveraging our community gas system services and our bulk delivery capabilities; |
| utilizing our expertise across our various businesses to improve overall performance; |
| enhancing marketing channels to attract new customers; |
| providing reliable and responsive customer service to retain existing customers; |
| maintaining a capital structure that enables us to access capital as needed; |
| maintaining a consistent and competitive dividend for shareholders; and |
| creating and maintaining a diversified customer base, energy portfolio and utility
foundation. |
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Increase | ||||||||||||
For the Three Months Ended September 30, | 2011 | 2010 | (decrease) | |||||||||
(in thousands except per share) | ||||||||||||
Business Segment: |
||||||||||||
Regulated Energy |
$ | 7,023 | $ | 6,536 | $ | 487 | ||||||
Unregulated Energy |
(1,472 | ) | (2,237 | ) | 765 | |||||||
Other |
43 | 284 | (241 | ) | ||||||||
Operating Income |
5,594 | 4,583 | 1,011 | |||||||||
Other Income |
649 | 102 | 547 | |||||||||
Interest Charges |
2,389 | 2,256 | 133 | |||||||||
Income Taxes |
1,457 | 801 | 656 | |||||||||
Net Income |
$ | 2,397 | $ | 1,628 | $ | 769 | ||||||
Earnings Per Share of Common Stock |
||||||||||||
Basic |
$ | 0.25 | $ | 0.17 | $ | 0.08 | ||||||
Diluted |
$ | 0.25 | $ | 0.17 | $ | 0.08 |
| Eastern Shores new service on the eight-mile mainline extension to interconnect with
TETLPs pipeline system, which commenced in January 2011, generated $542,000 of additional
gross margin in the quarter. These new services for 19,324 Mcfs per
day are expected to generate annual gross
margin of approximately $1.9 million.
Based upon the proposed settlement (see further discussion later in
the section), as the services increase in November 2011 to 33,817
Mcfs per day, the new rate under the proposed settlement for these
incremental services will negate the gross margin impact from the
increase in volumes. In November
2012, as the new services increase to 38,647 Mcfs per day, additional
annual gross margin of approximately $263,000 is expected to be
generated from these services.
|
| Eastern Shore entered into two additional transportation service agreements with an
existing industrial customer, one for the period of May 2011 through April 2021 for an
additional 3,290 Mcfs per day and the other for the period of November 2011 through October
2012 for an additional 9,192 Mcfs per day. These new services generated additional gross
margin of $92,000 in the third quarter of 2011. The 10-year service from May 2011 to April
2021 is expected to generate gross margin of $243,000 in 2011 and $361,000 annually
thereafter. The one-year service from November 2011 to October 2012 is expected to
generate gross margin of $168,000 in 2011 and $842,000 in 2012. |
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| Eastern Shore, FERC Staff and other interested parties in Eastern Shores base rate
proceeding reached a settlement in principle, which provides a cost of service of
approximately $29.1 million and pre-tax return of 13.9 percent. This represents an annual
rate increase of approximately $805,000, effective July 29, 2011. The settlement also
includes a rate reduction, effective November
1, 2011, to correspond with the 15,000 Dts/d (approximately 14,493
Mcfs per day)
phase-in of new transportation services on Eastern Shores eight-mile extension. This
rate reduction fully offsets the increased revenue that would have been generated
from the 15,000 Dts/d increase in firm service. The settlement also provides a five-year moratorium on the
parties rights to challenge Eastern Shores rates and on Eastern Shores right to file a
base rate increase. The settlement allows Eastern Shore to file for rate adjustments
during those five years in the event certain costs related to government-mandated
obligations are incurred and Eastern Shores pre-tax earnings do not equal or exceed 13.9
percent. Eastern Shore expects to finalize the settlement with the parties in November
2011 and submit it to the FERC for approval. The FERCs approval is
expected by late
2011 or early 2012. Starting in July 2011, Eastern Shore adjusted its billing to reflect
the rates requested in the base rate proceeding, subject to refund to customers upon the
conclusion of this proceeding. Eastern Shore recorded approximately
$911,000 as a regulatory
liability as of September 30, 2011, to fully reserve any incremental revenues generated by
the new rates until the settlement is filed and approved by the FERC. |
| The Come-Back filing in Florida, which includes our request for recovery, through
rates, of approximately $34.2 million in acquisition adjustment and $2.2 million in
merger-related costs, is also still underway. We expect the Florida PSC to address our
request at the November 2011 agenda conference. If the Florida PSC approves recovery of
the acquisition adjustment and merger-related costs, we would be able to classify these
amounts as regulatory assets and include them in our investment, or rate base, when
determining our Florida natural gas rates. Additionally, we would calculate our rate of
return based upon this higher level of investment, which would effectively enable us to
earn a return on this investment. We would also be able to amortize the acquisition
adjustment and merger-related costs, which may reduce our earnings by as much as $1.6
million annually until 2014 and $1.1 million annually thereafter until 2039. This
amortization expense would be a non-cash charge and included in the calculation of our
rates, which, along with the recovery of these assets, will increase our earnings and cash
flows above what we would have otherwise been able to achieve. |
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Table of Contents
Increase | ||||||||||||
For the Three Months Ended September 30, | 2011 | 2010 | (decrease) | |||||||||
(in thousands, except degree-day and customer information) | ||||||||||||
Revenue |
$ | 53,789 | $ | 53,412 | $ | 377 | ||||||
Cost of sales |
25,811 | 27,257 | (1,446 | ) | ||||||||
Gross margin |
27,978 | 26,155 | 1,823 | |||||||||
Operations & maintenance |
14,938 | 13,881 | 1,057 | |||||||||
Depreciation & amortization |
4,132 | 3,722 | 410 | |||||||||
Other taxes |
1,885 | 2,016 | (131 | ) | ||||||||
Other operating expenses |
20,955 | 19,619 | 1,336 | |||||||||
Operating Income |
$ | 7,023 | $ | 6,536 | $ | 487 | ||||||
Weather
and Customer Analysis |
||||||||||||
Delmarva Peninsula |
||||||||||||
Heating degree-days (HDD): |
||||||||||||
Actual |
49 | 50 | (1 | ) | ||||||||
10-year average |
53 | 60 | (7 | ) | ||||||||
Per residential customer added: |
||||||||||||
Estimated gross margin |
$ | 375 | $ | 375 | $ | 0 | ||||||
Estimated other operating expenses |
$ | 111 | $ | 105 | $ | 6 | ||||||
Florida |
||||||||||||
HDD: |
||||||||||||
Actual |
0 | 0 | 0 | |||||||||
10-year average |
0 | 0 | 0 | |||||||||
Cooling degree-days: |
||||||||||||
Actual |
1,569 | 1,654 | (85 | ) | ||||||||
10-year average |
1,483 | 1,466 | 17 | |||||||||
Residential Customer Information |
||||||||||||
Average number of customers: |
||||||||||||
Delmarva natural gas distribution |
47,810 | 46,908 | 902 | |||||||||
Florida natural gas distribution |
61,261 | 60,813 | 448 | |||||||||
Florida electric distribution |
23,583 | 23,594 | (11 | ) | ||||||||
Total |
132,654 | 131,315 | 1,339 | |||||||||
- 37 -
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| Customer growth generated a $385,000 increase in gross margin in the third quarter of
2011, compared to the same quarter in 2010. Commercial and industrial customer growth, due
primarily to additional gross margin generated from 21 large commercial and industrial
services added since July 2010, generated $337,000 of this increase. These 21 new large
commercial and industrial services are expected to generate annual gross margin of $1.2
million in 2011. The same services generated $196,000 of gross margin following their
addition in the second half of 2010. Two-percent growth in residential customers generated
an additional $58,000 in gross margin. |
| Offsetting these gross margin increases were decreases in gross margin of $68,000 and
$37,000 attributable to a change in customer rates and rate classes and decreased
non-weather-related customer consumption, respectively. |
| During the third quarter of 2010, the Florida natural gas distribution operation
recorded an accrual of $500,000 to reserve for regulatory risk. The establishment of this
reserve was based on managements assessment of its earnings and the risk associated with
possible action by the Florida PSC related to our request for recovery of the acquisition
adjustment and merger-related costs. |
| Two-percent growth in commercial customers and the addition of 700 customers as a result
of our purchase of the operating assets of Indiantown Gas Company in August 2010, generated
additional gross margin of $200,000 in the third quarter of 2011, compared to the same
quarter in 2010. |
| New transportation services associated with Eastern Shores eight-mile mainline
extension to interconnect with TETLPs pipeline system generated an additional $542,000 of
gross margin in the third quarter of 2011. These new services for
19,324 Mcfs per day, which commenced in January 2011,
are expected to generate annual gross margin of approximately $1.9 million.
Based upon the proposed settlement discussed previously, as the services increase in November 2011 to
33,817 Mcfs per day, the new rate under the proposed settlement of these incremental services will negate
the gross margin impact from
the increase in volumes. In November 2012, as the new services increase to 38,647 Mcfs per day, additional
annual gross margin of approximately $263,000 is expected to be generated from these services.
|
| Eastern Shore entered into two additional transportation service agreements with an
existing industrial customer, one for the period of May 2011 through April 2021 for an
additional 3,290 Mcfs per day and the other for the period of November 2011 through October
2012 for an additional 9,192 Mcfs. These services generated additional gross margin of
$92,000 in the third quarter of 2011. The 10-year service from May 2011 to April 2021 is
expected to generate gross margin of $243,000 in 2011 and $361,000 annually thereafter.
The one-year service from November 2011 to October 2012 is expected to generate gross
margin of $168,000 in 2011 and $842,000 in 2012. |
| New transportation services
implemented by Eastern Shore in November 2010 as a result of
its system expansion projects generated an additional $83,000 of gross margin in the third
quarter of 2011, compared to the same quarter in 2010. This expansion added 1,546 Mcfs per
day and an estimated annual gross margin of $351,000 in 2011. In 2010, this project
generated $56,000 of gross margin. |
- 38 -
Table of Contents
| The remaining gross margin increase of $113,000 was attributable primarily to higher
volumes delivered during the third quarter of 2011 on a non-recurring basis to customers that
operate electric generation facilities. |
Other operating expenses for the regulated energy segment increased by $1.3 million, or seven percent, in the third quarter of 2011, compared to the same period in 2010, due largely to the following factors:
| $260,000 in higher depreciation expense and asset removal costs from capital investments
made since the third quarter of 2010; |
| $220,000 in increased costs
related to Florida customer-service-related activities, due to
service enhancements; |
| $212,000 in additional expenses related to pipeline integrity projects for Eastern Shore
to comply with increased pipeline regulatory requirements; |
| $173,000 related to a one-time pension charge allocated to the regulated energy
operations during the quarter; |
| $145,000 in increased regulatory, legal and other costs associated with the electric
franchise dispute in Marianna, Florida; and |
| $122,000 in additional costs related to maintenance of mains, electric lines and
facilities. |
Increase | ||||||||||||
For the Three Months Ended September 30, | 2011 | 2010 | (decrease) | |||||||||
(in thousands, except degree-day data) | ||||||||||||
Revenue |
$ | 23,721 | $ | 20,134 | $ | 3,587 | ||||||
Cost of sales |
18,622 | 15,714 | 2,908 | |||||||||
Gross margin |
5,099 | 4,420 | 679 | |||||||||
Operations & maintenance |
5,552 | 5,435 | 117 | |||||||||
Depreciation & amortization |
739 | 896 | (157 | ) | ||||||||
Other taxes |
280 | 326 | (46 | ) | ||||||||
Other operating expenses |
6,571 | 6,657 | (86 | ) | ||||||||
Operating Loss |
$ | (1,472 | ) | $ | (2,237 | ) | $ | 765 | ||||
Weather Analysis Delmarva Peninsula |
||||||||||||
Actual HDD |
49 | 50 | (1 | ) | ||||||||
10-year average HDD |
53 | 60 | (7 | ) |
- 39 -
Table of Contents
| Our Delmarva propane distribution operation generated additional gross margin of
$184,000 in the third quarter of 2011, compared to the same quarter in 2010. A favorable
physical inventory adjustment and the positive differential between propane wholesale
prices and our average cost of inventory during the third quarter of 2011 contributed to
the increased margins per gallon on the Delmarva Peninsula. |
| The remaining gross margin increase of $90,000 is due primarily to increased wholesale
margins and higher fees generated from continued growth and successful implementation of
various customer pricing programs, slightly offset by a decrease in gross margins
attributable to decreased non-weather-related customer consumption. |
- 40 -
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Increase | ||||||||||||
For the Three Months Ended September 30, | 2011 | 2010 | (decrease) | |||||||||
(in thousands) | ||||||||||||
Revenue |
$ | 3,100 | $ | 2,920 | $ | 180 | ||||||
Cost of sales |
1,684 | 1,524 | 160 | |||||||||
Gross margin |
1,416 | 1,396 | 20 | |||||||||
Operations & maintenance |
1,099 | 905 | 194 | |||||||||
Depreciation & amortization |
107 | 70 | 37 | |||||||||
Other taxes |
167 | 137 | 30 | |||||||||
Other operating expenses |
1,373 | 1,112 | 261 | |||||||||
Operating Income Other |
43 | 284 | (241 | ) | ||||||||
Operating Income Eliminations |
| | | |||||||||
Operating Income |
$ | 43 | $ | 284 | $ | (241 | ) | |||||
- 41 -
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Increase | ||||||||||||
For the Nine Months Ended September 30, | 2011 | 2010 | (decrease) | |||||||||
(in thousands, except per share) | ||||||||||||
Business Segment: |
||||||||||||
Regulated Energy |
$ | 31,194 | $ | 32,360 | ($1,166 | ) | ||||||
Unregulated Energy |
7,047 | 4,732 | 2,315 | |||||||||
Other |
(32 | ) | 650 | (682 | ) | |||||||
Operating Income |
38,209 | 37,742 | 467 | |||||||||
Other Income |
699 | 206 | 493 | |||||||||
Interest Charges |
6,654 | 6,924 | (270 | ) | ||||||||
Income Taxes |
12,590 | 12,082 | 508 | |||||||||
Net Income |
$ | 19,664 | $ | 18,942 | $ | 722 | ||||||
Earnings Per Share of Common Stock |
||||||||||||
Basic |
$ | 2.06 | $ | 2.00 | $ | 0.06 | ||||||
Diluted |
$ | 2.04 | $ | 1.98 | $ | 0.06 |
| Eastern Shores new service on the eight-mile mainline extension to interconnect with
TETLPs pipeline system, which commenced in January 2011, generated $1.6 million of the
additional gross margin in the
first nine months of 2011. These new services for 19,324 Mcfs per day are expected to generate annual gross margin
of approximately $1.9 million.
Based upon the proposed settlement discussed previously, as the services increase in November 2011 to
33,817 Mcfs per day, the new rate under the proposed settlement for these incremental services will negate
the gross margin impact from the increase in volumes. In November 2012, as the new services increase to 38,647 Mcfs per day, additional
annual gross margin of approximately $263,000 is expected to be generated from these services. |
- 42 -
Table of Contents
| Eastern Shore entered into two additional transportation service agreements with an
existing industrial customer, one for the period of May 2011 through April 2021 for an
additional 3,290 Mcfs per day and the other for the period of November 2011 through October
2012 for an additional 9,192 Mcfs per day. These new services generated additional gross
margin of $154,000 in the first nine months of 2011. The 10-year service from May 2011 to
April 2021 is expected to generate gross margin of $243,000 in 2011 and $361,000 annually
thereafter. The one-year service from November 2011 to October 2012 is expected to
generate gross margin of $168,000 in 2011 and $842,000 in 2012. |
| Also generating additional gross margin of $330,000 in the first nine months of 2011,
compared to the same period in 2010, were new transportation services that commenced in May
and November 2010 as a result of Eastern Shores system expansion projects. These
expansions added 2,666 Mcfs per day of capacity with an estimated annual gross margin of
$606,000 in 2011 ($431,000 in the first nine months of 2011). These projects generated
$216,000 of gross margin in 2010 ($40,000 in the first nine months of 2010). |
- 43 -
Table of Contents
| Eastern Shore, FERC Staff and other interested parties in Eastern Shores base rate
proceeding reached a settlement in principle, which provides a cost of service of
approximately $29.1 million and pre-tax return of 13.9 percent. This represents an annual
rate increase of approximately $805,000, effective July 29, 2011. The settlement also
includes a rate reduction, effective November
1, 2011, associated with the 15,000 Dts/d (approximately 14,493 Mcfs perday)
phase-in of new transportation services on Eastern Shores eight-mile extension. This
rate reduction fully offsets the increased revenue that would have been generated
from the 15,000 Dts/d increase in firm service. The settlement also provides a five-year moratorium on the
parties rights to challenge Eastern Shores rates and on Eastern Shores right to file a
base rate increase. The settlement allows Eastern Shore to file for rate adjustments
during those five years in the event certain costs related to government-mandated
obligations are incurred and Eastern Shores pre-tax earnings do not equal or exceed 13.9
percent. Eastern Shore expects to finalize the settlement with the parties in November
2011 and submit it to the FERC for approval. The FERCs approval is
expected by late
2011 or early 2012. Starting in July 2011, Eastern Shore adjusted its billing to reflect
the rates requested in the base rate proceeding, subject to refund to customers upon the
conclusion of this proceeding. Eastern Shore recorded approximately $911,000 as regulatory
liability as of September 30, 2011, to fully reserve any incremental revenues generated by
the new rates until the settlement is filed and approved by the FERC. |
| The Come-Back filing in Florida, which includes our request for recovery, through
rates, of approximately $34.2 million in acquisition adjustment and $2.2 million in
merger-related costs, is also still underway. We expect the Florida PSC to address our
request at the November 2011 agenda conference. If the Florida PSC approves recovery of
the acquisition adjustment and merger-related costs, we would be able to classify these
amounts as regulatory assets and include them in our investment, or rate base, when
determining our Florida natural gas rates. Additionally, we would calculate our rate of
return based upon this higher level of investment, which would effectively enable us to
earn a return on this investment. We would also be able to amortize the acquisition
adjustment and merger-related costs, which may reduce our earnings by as much as $1.6
million annually until 2014 and $1.1 million annually thereafter until 2039. This
amortization expense would be a non-cash charge and included in the calculation of our
rates, which, along with the recovery of these assets, will increase our earnings and cash
flows above what we would have otherwise been able to achieve. |
- 44 -
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- 45 -
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Increase | ||||||||||||
For the Nine Months Ended September 30, | 2011 | 2010 | (decrease) | |||||||||
(in thousands, except degree-day and customer information) | ||||||||||||
Revenue |
$ | 193,118 | $ | 197,779 | ($4,661 | ) | ||||||
Cost of sales |
98,683 | 106,146 | (7,463 | ) | ||||||||
Gross margin |
94,435 | 91,633 | 2,802 | |||||||||
Operations & maintenance |
44,800 | 41,771 | 3,029 | |||||||||
Depreciation & amortization |
12,319 | 11,199 | 1,120 | |||||||||
Other taxes |
6,122 | 6,303 | (181 | ) | ||||||||
Other operating expenses |
63,241 | 59,273 | 3,968 | |||||||||
Operating Income |
$ | 31,194 | $ | 32,360 | $ | (1,166 | ) | |||||
Weather and Customer Analysis |
||||||||||||
Delmarva Peninsula |
||||||||||||
Heating degree-days (HDD): |
||||||||||||
Actual |
2,876 | 3,021 | (145 | ) | ||||||||
10-year average |
2,905 | 2,923 | (18 | ) | ||||||||
Per residential customer added: |
||||||||||||
Estimated gross margin |
$ | 375 | $ | 375 | $ | 0 | ||||||
Estimated other operating expenses |
$ | 111 | $ | 105 | $ | 6 | ||||||
Florida |
||||||||||||
HDD: |
||||||||||||
Actual |
534 | 942 | (408 | ) | ||||||||
10-year average |
594 | 547 | 47 | |||||||||
Cooling degree-days: |
||||||||||||
Actual |
2,676 | 2,694 | (18 | ) | ||||||||
10-year average |
2,444 | 2,418 | 26 | |||||||||
Residential Customer Information |
||||||||||||
Average number of customers: |
||||||||||||
Delmarva natural gas distribution |
48,594 | 47,508 | 1,086 | |||||||||
Florida natural gas distribution |
61,489 | 61,087 | 402 | |||||||||
Florida electric distribution |
23,588 | 23,570 | 18 | |||||||||
Total |
133,671 | 132,165 | 1,506 | |||||||||
- 46 -
Table of Contents
| Lower customer consumption during the first nine months of 2011, compared to the same
period in 2010, due primarily to significantly warmer weather during the heating season,
decreased gross margin by $1.6 million. Heating degree-days in Florida decreased by 43
percent, or 408 heating degree-days, during the first nine months of 2011, compared to the
same period in 2010. |
| Offsetting the decrease from lower customer consumption are: (1) two-percent growth in
commercial customers for our Florida natural gas distribution operation, which generated
additional gross margin of $754,000 in the first nine months of 2011, compared to the same
period in 2010; and (2) 700 new customers, added as a result of our purchase of the
operating assets of Indiantown Gas Company in August 2010, which generated $367,000 in
additional gross margin in the first nine months of 2011. |
| New transportation services associated with Eastern Shores eight-mile mainline
extension to interconnect with TETLPs pipeline system generated an additional $1.6
million of gross margin in the nine months ended September 30,
2011. These new services for 19,324 Mcfs per day,
which commenced in January 2011, are expected to generate annual gross margin of
approximately $1.9 million. Based upon the proposed settlement discussed previously, as the services increase in
November 2011 to 33,817 Mcfs per day, the new rate under the proposed settlement of these incremental services will negate
the gross margin impact from the
increase in volumes. In November 2012, as the new services increase to 38,647 Mcfs per day, additional annual gross margin of
approximately $263,000 is expected to be generated from these services. |
| New transportation services implemented by Eastern Shore in May 2010 and November 2010
as a result of its system expansion projects generated an additional $330,000 of gross
margin during the first nine months of 2011, compared to 2010. These expansions added
2,666 Mcfs of capacity per day and an estimated annual gross margin of $606,000 in 2011.
These projects generated $216,000 of gross margin in 2010. |
| Eastern Shore entered into two additional transportation services agreements with an
existing industrial customer, one for the period of May 2011 through April 2021 for an
additional 3,290 Mcfs per day and the other for the period of November 2011 through October
2012 for an additional 9,192 Mcfs per day. These services generated additional gross
margin of $154,000 in the first nine months of 2011. The 10-year service from May 2011 to
April 2021 is expected to generate gross margin of $243,000 in 2011 and $361,000 annually
thereafter. The one-year service from November 2011 to October 2012 is expected to
generate gross margin of $168,000 in 2011 and $842,000 in 2012. |
| The foregoing increases to gross margin were offset by the expiration of two small firm
transportation service contracts in April 2010, decreasing gross margin by $40,000 in the
first nine months of 2011.
|
- 47 -
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| $820,000 in higher depreciation expense and asset removal costs form capital investments
made since the third quarter of 2010; |
| Increased regulatory, legal and other costs, including $439,000 of additional costs
associated with the electric franchise dispute in Marianna, Florida and $245,000 in costs
with respect to the Come-Back filing in Florida, the rate case proceeding for Eastern
Shore and other regulatory proceedings; |
| $628,000 in additional expenses related to pipeline integrity projects for Eastern Shore
to comply with increased pipeline regulatory requirements; |
| $202,000 in higher costs related to maintenance of mains, electric lines and facilities; |
| a reduction of $139,000 in expense for the nine months ended September 2010, resulting
from a reversal of bad debt expense, which was previously reserved for a receivable from a
Florida electric customer in bankruptcy; and |
| $192,000 in increased payroll costs, due primarily to higher accruals for
performance incentive compensation. |
Increase | ||||||||||||
For the Nine Months Ended September 30, | 2011 | 2010 | (decrease) | |||||||||
(in thousands, except degree-day data) | ||||||||||||
Revenue |
$ | 112,164 | $ | 104,018 | $ | 8,146 | ||||||
Cost of sales |
84,227 | 78,740 | 5,487 | |||||||||
Gross margin |
27,937 | 25,278 | 2,659 | |||||||||
Operations & maintenance |
17,475 | 16,792 | 683 | |||||||||
Depreciation & amortization |
2,301 | 2,660 | (359 | ) | ||||||||
Other taxes |
1,114 | 1,094 | 20 | |||||||||
Other operating expenses |
20,890 | 20,546 | 344 | |||||||||
Operating Income |
$ | 7,047 | $ | 4,732 | $ | 2,315 | ||||||
Weather Analysis Delmarva Peninsula |
||||||||||||
Actual HDD |
2,876 | 3,021 | (145 | ) | ||||||||
10-year average HDD |
2,905 | 2,923 | (18 | ) |
- 48 -
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| Our Delmarva propane distribution operation generated additional gross margin of $1.2
million due to higher margins per gallon during the first nine months of 2011, compared to
the same period in 2010, as margins per gallon returned to more normal levels during the
current period. Propane margins per gallon during the first half of 2010 were low,
compared to historical levels, due to additional spot purchases at increased costs during
the peak heating season to meet the weather-related increase in customer consumption. More
normal temperatures and fewer spot purchases during 2011 resulted in margins per gallon
returning to more normal levels. |
| A one-time gain of $575,000 was recorded in the first nine months of 2011, as a result
of our share of proceeds received from an antitrust litigation settlement with a major
propane supplier. |
| An increase in other fees generated additional gross margin of $174,000, due primarily
to the continued growth and successful implementation of various customer pricing programs. |
| A decline in volumes sold in the first nine months of 2011, compared to the same period
in 2010, decreased gross margin by $287,000. This decrease was attributable to timing of
deliveries to bulk customers and a decrease in weather-related consumption due to the
warmer temperatures on the Delmarva Peninsula. |
- 49 -
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Increase | ||||||||||||
For the Nine Months Ended September 30, | 2011 | 2010 | (decrease) | |||||||||
(in thousands) | ||||||||||||
Revenue |
$ | 8,757 | $ | 7,990 | $ | 767 | ||||||
Cost of sales |
4,790 | 3,973 | 817 | |||||||||
Gross margin |
3,967 | 4,017 | (50 | ) | ||||||||
Operations & maintenance |
3,145 | 2,672 | 473 | |||||||||
Depreciation & amortization |
316 | 216 | 100 | |||||||||
Other taxes |
538 | 479 | 59 | |||||||||
Other operating expenses |
3,999 | 3,367 | 632 | |||||||||
Operating Income Other |
(32 | ) | 650 | (682 | ) | |||||||
Operating Income Eliminations |
| | | |||||||||
Operating (Loss) Income |
$ | (32 | ) | $ | 650 | $ | (682 | ) | ||||
- 50 -
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- 51 -
Table of Contents
September 30, | December 31, | |||||||||||||||
(in thousands) | 2011 | 2010 | ||||||||||||||
Long-term debt, net of current maturities |
$ | 117,069 | 33 | % | $ | 89,642 | 28 | % | ||||||||
Stockholders equity |
237,548 | 67 | % | 226,239 | 72 | % | ||||||||||
Total capitalization, excluding
short-term debt |
$ | 354,617 | 100 | % | $ | 315,881 | 100 | % | ||||||||
September 30, | December 31, | |||||||||||||||
(in thousands) | 2011 | 2010 | ||||||||||||||
Short-term debt |
$ | 26,591 | 7 | % | $ | 63,958 | 16 | % | ||||||||
Long-term debt,
including current
maturities |
126,265 | 32 | % | 98,858 | 25 | % | ||||||||||
Stockholders equity |
237,548 | 61 | % | 226,239 | 59 | % | ||||||||||
Total capitalization,
including short-term
debt |
$ | 390,404 | 100 | % | $ | 389,055 | 100 | % | ||||||||
For the Nine Months Ended September 30, | 2011 | 2010 | ||||||
(in thousands) | ||||||||
Net Income |
$ | 19,664 | $ | 18,942 | ||||
Non-cash adjustments to net income |
32,769 | 26,901 | ||||||
Changes in assets and liabilities |
341 | 8,951 | ||||||
Net cash provided by operating activities |
$ | 52,774 | $ | 54,794 | ||||
- 52 -
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| Net cash flows related to income taxes, which include deferred income taxes in non-cash
adjustments to net income and the change in income taxes receivable, increased by $7.7
million in the first nine months of 2011, compared to the same period in 2010, due
primarily to the 100-percent bonus depreciation deduction allowed in 2011, which is
reducing our income tax payments in the current period. |
| Net cash flows from receivables and payables in the natural gas and propane distribution
operations decreased by $6.2 million, offset partially by an increase in net cash flows
due primarily to the timing of collections and payments of trading contracts entered into
by our propane wholesale marketing operation. |
| Net cash flows from accrued compensation decreased by $2.0 million, as a result of a
smaller decrease in the change in accrued payroll due to timing of payroll periods and
higher incentive compensation and severance payments in the first nine months of 2011. |
| Net cash flows from the changes in regulatory assets and liabilities decreased by
approximately $2.0 million, primarily as a result of a reduction in fuel costs due and
collected from rate payers. |
| During the first nine months of 2011 we had a net repayment of $9.3 million under our
line of credit agreements related to working capital, compared to $23.1 million during the
same period in 2010, resulting in a period-over-period net cash increase of $13.7 million.
Changes in cash overdrafts decreased by $5.9 million, resulting in a period-over-period net
cash increase. |
| Net repayments of other short-term debt and long-term debt during the first nine months
of 2011 were $1.5 million, compared to net repayments of $2.1 million in the same period in
2010. During the first nine months of 2010, we redeemed the 6.85 and 4.90 percent series of
FPUs secured first mortgage bonds prior to their respective maturities by using the
proceeds from a new short-term credit facility. During the first nine months of 2011, we
issued Chesapeakes unsecured senior notes, using the proceeds to repay the new short-term
credit facility and permanently finance the FPU bonds. |
| We paid $8.7 million and $8.2 million in cash dividends for the nine months ended
September 30, 2011 and 2010, respectively. |
- 53 -
Table of Contents
Payments Due by Period | ||||||||||||||||||||
Purchase Obligations | Less than 1 year | 1 - 3 years | 3 - 5 years | More than 5 years | Total | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Commodities (1) |
$ | 19,463 | $ | 366 | $ | | $ | | $ | 19,829 | ||||||||||
Propane (2) |
54,115 | | | | 54,115 | |||||||||||||||
Total Purchase Obligations |
$ | 73,578 | $ | 366 | $ | | $ | | $ | 73,944 | ||||||||||
(1) | In addition to the obligations noted above, the natural gas
distribution, the electric distribution and propane distribution operations
have agreements with commodity suppliers that have provisions with no
minimum purchase requirements. There are no monetary penalties for
reducing the amounts purchased; however, the propane contracts allow the
suppliers to reduce the amounts available in the winter season if we do not
purchase specified amounts during the summer season. Under these contracts,
the commodity prices will fluctuate as market prices fluctuate. |
|
(2) | We have also entered into forward sale contracts in the aggregate
amount of $32.5 million. See Part I, Item 3, Quantitative and Qualitative
Disclosures about Market Risk, below, for further information. |
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Item 3. | Quantitative and Qualitative Disclosures about Market Risk |
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Quantity in | Estimated Market | Weighted Average | ||||||||||
At September 30, 2011 | Gallons | Prices | Contract Prices | |||||||||
Forward Contracts |
||||||||||||
Sale |
21,361,200 | $ | 1.3900 $1.6200 | $ | 1.5231 | |||||||
Purchase |
21,193,200 | $ | 1.3344 $1.6047 | $ | 1.5149 |
September 30, | December 31, | |||||||
(in thousands) | 2011 | 2010 | ||||||
Mark-to-market energy assets, including put option |
$ | 1,229 | $ | 1,642 | ||||
Mark-to-market energy liabilities |
$ | 956 | $ | 1,492 |
Item 4. | Controls and Procedures |
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As disclosed in Note 5, Other Commitments and Contingencies, of the unaudited
condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we
are involved in certain legal actions and claims arising in the normal course of
business. We are also involved in certain legal and administrative proceedings before
various governmental or regulatory agencies concerning rates and other regulatory
actions. In the opinion of management, the ultimate disposition of these proceedings
and claims will not have a material effect on our condensed consolidated financial
position, results of operations or cash flows. |
Our business, operations, and financial condition are subject to various risks and
uncertainties. The risk factors described in Part I, Item 1A. Risk Factors in our
Annual Report on Form 10-K for the year ended December 31, 2010, should be carefully
considered, together with the other information contained or incorporated by reference
in this Quarterly Report on Form 10-Q and in our other filings with the SEC in
connection with evaluating the Company, our business and the forward-looking statements
contained in this Report. Additional risks and uncertainties not presently known to us
or that we currently deem immaterial also may affect the Company. The occurrence of any
of these known or unknown risks could have a material adverse impact on our business,
financial condition, and results of operations. |
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
Total | Total Number of Shares | Maximum Number of | ||||||||||||||
Number of | Average | Purchased as Part of | Shares That May Yet Be | |||||||||||||
Shares | Price Paid | Publicly Announced Plans | Purchased Under the Plans | |||||||||||||
Period | Purchased | per Share | or Programs (2) | or Programs (2) | ||||||||||||
July 1, 2011
through July 31, 2011 (1) |
260 | $ | 40.06 | | | |||||||||||
August 1, 2011
through August 31, 2011 |
| $ | | | | |||||||||||
September 1, 2011
through September 30, 2011 |
| $ | | | | |||||||||||
Total |
260 | $ | 40.06 | | | |||||||||||
(1) | Chesapeake purchased shares of stock on the open market for the purpose of
reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain
Directors and Senior Executives under the Deferred Compensation Plan. The Deferred Compensation
Plan is discussed in detail in Item 8 under the heading Notes to the Consolidated Financial
Statements Note M, Employee Benefit Plans of our Form 10-K filed with the SEC on March 8, 2011. During the quarter, 260 shares were purchased through the
reinvestment of dividends on deferred stock units. |
|
(2) | Except for the purposes
described in Footnote (1), Chesapeake has no publicly announced plans or programs to
repurchase its shares. |
Item 3. | Defaults upon Senior Securities |
None. |
Item 5. | Other Information |
None. |
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Item 6. | Exhibits |
31.1 | Certificate of Chief Executive Officer of Chesapeake Utilities
Corporation pursuant to Rule 13a-14(a) under the Securities Exchange
Act of 1934, dated November 4, 2011. |
|||
31.2 | Certificate of Chief Financial Officer of Chesapeake Utilities
Corporation pursuant to Rule 13a-14(a) under the Securities Exchange
Act of 1934, dated November 4, 2011. |
|||
32.1 | Certificate of Chief Executive Officer of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated November 4,
2011. |
|||
32.2 | Certificate of Chief Financial Officer of Chesapeake Utilities
Corporation pursuant to 18 U.S.C. Section 1350, dated November 4,
2011. |
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Chesapeake Utilities Corporation |
||
/s/ Beth W. Cooper
|
||
Senior Vice President and Chief Financial Officer |
||
Date: November 4, 2011 |
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